Review of EPA’s Proposed Approval of a Revision 

to the State of Nevada’s State Implementation Plan 

to Implement the Regional Haze Program 

Comments on Determination of 

Best Available Retrofit Technology 

August 22, 2011 

prepared by 

Petra Pless, D.Env. 

Pless Environmental Consulting 

440 Nova Albion Way #2 

San Rafael, CA 94903 

and 

Bill Powers, P.E. 

Powers Engineering 

4452 Park Blvd., Suite 209 

San Diego, CA 92116 
ii 

Table of Contents 

I. EPA’s NOx BART Determinations for Reid Gardner Are Fundamentally 

Flawed ...................................................................................................................... 1

I.A NDEP’s NOx BART Determination for Reid Gardner Failed to Evaluate 

the Most Stringent NOx Emission Control Level for SCR ............................... 3

I.A.1 SCR Can Meet an Emission Limit of 0.05 lb/MMBtu NOx and ≥90% Control 

Efficiency ................................................................................................................................. 5

I.A.2 Cost-Effectiveness at Other Facilities Must Be Considered .................................... 20

I.B The Reid Gardner NOx Cost Analysis Is Fundamentally Flawed ................... 21

I.B.1 The Costs to Install SCR on Reid Gardner Are Overestimated ............................ 22

I.B.2 NDEP Improperly Modified the Baseline ...................................................................... 29

I.B.3 NDEP’s Cost Rejection Methodology Is Invalid .......................................................... 30

I.C EPA Fails to Provide Enforceable Compliance Provisions .............................. 36

I.C.1 Averaging Time.................................................................................................................... 36

I.C.2 Monitoring and Recordkeeping ....................................................................................... 38

I.C.3 Compliance Time ................................................................................................................ 38

I.D Alleged Negative Non-Air Quality Environmental Impacts Are 

Mischaracterized and Unsupported in the Record .......................................... 39

I.D.1 Alleged Impacts Are Not Supported in the Record ................................................... 39

I.D.2 Potential Non-Air Quality Environmental Impacts of SCR Compared to 

SNCR and Rotamix ............................................................................................................ 41

I.D.3 Impacts of Ammonia Slip on Salability of Fly Ash Are Mischaracterized .............. 44

I.D.4 Visible Plume Impacts Are Mischaracterized ............................................................... 44

I.D.5 Transportation Risk Can Be Avoided ............................................................................ 47

I.E EPA’s Proposed Higher Controlled Emission Rate for Unit 3 Compared 

to Units 1 and 2 for ROFA with Rotamix Is Not Justified ............................... 48

II. NDEP’s BART Determinations Do Not Follow the Methodology 

Assumed by the EPA ............................................................................................ 50

II.A NDEP Did Not Follow 40 CFR 51.308(e) .......................................................... 50

II.B NDEP Did Not Follow EPA’s BART Guidelines ............................................... 51

II.B.1 Averaging Time Is Incorrect ............................................................................................. 52

II.B.2 Design Parameters Are Missing....................................................................................... 52

II.B.3 Equipment List Is Missing .................................................................................................. 53

II.B.4 Documentation for Cost Estimates Is Missing ............................................................. 54

II.B.5 Other Missing Documents, Modeling Files, and Information ................................... 55

II.B.6 Costing Methodology Is Inconsistent With BART Guidelines ................................. 56

II.C NDEP’s Analysis Did Not Follow EPA’s Air Pollution Control Cost 

Manual .................................................................................................................. 56
iii 

Tables 

Table 1: Baseline years, baseline (pre-BART) NOx emission rates, and NOx control efficiency for 

control scenarios evaluated by NDEP for Reid Gardner 

Table 2: Achievable controlled NOx emission rates at Reid Gardner based on NDEP baseline 

and SCR with 90% control efficiency 

Table 3: Design criteria for Seminole Units 1 and 2 

Table 4: Trimble County acceptance test results 

Table 5: Desert Rock NOx permit limits (lb/MMBtu) 

Table 6: Average cost-effectiveness for control option 5: LNB/OFA + SCR 

Figures 

Figure 1: NDEP’s least-cost envelope for Reid Gardner Unit 3 

Figure 2: EPA BART Guidelines example for least-cost envelope determination of 

dominant/inferior controls 

Figure 3: Reid Gardner Units 1-3 historic annual average NOx emission rates and proposed NOx 

BART limits 

Attachments 

Attach. 1: NOx design efficiencies of retrofit SCRs in the CAMD database and the ICAC White 

Paper 

Attach. 2: Information compiled from EPA’s CAMD database 

Attach. 3: Compilation of SCR control efficiency data from vendor experience lists, technical 

papers, and McIlvaine databases 

Attach. 4a, 4b, 4c: Reverse engineered cost analyses from 10/09 CH2MHill BART Analyses for Units 1, 

2, 3, respectively 

Attach. 5a, 5b, 5c: Spreadsheets to support revised cost analyses for Units 1, 2, 3, respectively 

Exhibits 

Ex. 1: Environmental Protection Agency, 40 CFR Part 52, [EPA-R06-OAR-2010-0846; FRL-], 

Approval and Promulgation of Implementation Plans; New Mexico; Federal Implementation 

Plan for Interstate Transport of Pollution Affecting Visibility and Best Available Retrofit 

Technology Determination, signed by L.P. Jackson, dated August 4, and supporting Technical 

Support Document 

Ex. 2: California Air Resources Board, Compliance Assistance Technical Manual Series: Stationary 

Source Air Pollution Control Devices and Techniques, Section 310: Selective Non-Catalytic 

Reduction Control Theory and Design 
iv 

Ex. 3: Haldor Topsoe, Experience List, October 2009 

Ex. 4: Hitachi, NOx Removal Coal Plant Supply List, October 23, 2002 

Ex. 5: Argillon Experience List U.S. Coal Plant 

Ex. 6: CERAM Reference List, August 2006 

Ex. 7: Hitachi, SCR System and NOx Catalyst Experience, Coal, February 2010 

Ex. 8: Kurtides, T., Lessons Learned from SCR Reactor Retrofit, COAL-GEN, Columbus, OH, 

August 6-8, 2003, Sargent and Lundy 

Ex. 9: Rutherford, S., Coal-Fired SCR Applications in the US – Challenges and Strategies for 

Successful Operation and Emission Compliance, Cormetech Inc., VGB Workshop “Flue Gas 

Cleaning 2007,” Vienna, Austria, May 22–23, 2007 

Ex. 10: Karina Rigby and others, SCR: The Most Effective Technology for NOx Reduction in Large 

Combustion Plants 

Ex. 11: H. Jensen-Holm, N.-Y. Topsøe, J.J. Cui, Implementation of SCR DeNOx Technology on CoalFired Boilers in P.R. China, Haldor Topsoe, August 2006 

Ex. 12: James E. Staudt and Clayton Erickson. Selective Catalytic Reduction System Performance and 

Reliability Review, Andover Technology Partners 

Ex. 13: McIlvaine, Utility E-Alert #798, November 3, 2006 

Ex. 14: Srivastava et al., Nitrogen Oxides Emission Control Options for Coal-Fired Electric Utility 

Boilers, J. Air & Waste Manage. Assoc., Vol 55, pp. 1367-1388, Table 4 

Ex. 15: M. J. Oliva and S.R. Khan, Performance Analysis of SCR Installations on Coal-Fired Boilers, 

Pittsburgh Coal Conference, September 2005 

Ex. 16: Callie A. Videtich, Director Air Program, EPA Region 8, Letter to Paul Tourangeau, Director, 

Colorado Department of Public Health and the Environment, Re: Regional Haze State 

Implementation Plan, October 26, 2010 

Ex. 17: Clay Erickson, Robert Lisauskas, and Anthony Licata, What’s New in SCRs, DOE’s 

Environmental Control Conference, May 16, 2006 

Ex. 18: B. Butler and R.P. Gaikwad, Operating Experience of SCRs at Texas Genco’s Coal and Gas 

Fired Power Plants, Mega Symposium 2004 

Ex. 19: W.J. Gretta, D. Harajda, A.C. Favale, and T.J. Wess, The SCR Retrofit Design for the Seminole 

Generating Station 

Ex. 20: Email from Andrew Gray to Petra Pless, Re: NDEP Spreadsheets, August 20, 2011, and Excel 

spreadsheet ‘Copy Acid Rain Annual Data BART NVE (4).xls’ provided via email by Adele 

Malone, NDEP, to Andrew Gray, Gray Sky Solutions, on August 11, 2011 

Ex. 21: R. Peltier, Top Plants: Seminole Generating Station, Palatka, Florida, Power, October 1, 2009 

Ex. 22: K. Bresnahan, C. Erickson, M. Phillipo, S. Dean, and B. Rogan, Design, Installation and Startup 

Experience on a High Removal Efficiency SCR System at Morgantown Generating Station Units 

1&2, Mega 2008 

Ex. 23: E. Saunders, S. Straight, E. Pear, C. Erickson, H. Culberson, and M. Kelly, SCR System 

Performance at LG&E’s Trimble County Generating Station, EPRI Workshop on Selective 

Catalytic Reduction, Atlanta, GA, October 22-23, 2002 

Ex. 24: J. Cooper, W.J. Gretta, A.C. Favale, and H.N. Franklin, First Application of Babcock-Hitachi 

K.K. Low SO2 to SO3 Oxidation Catalyst at the IPL Petersburg Generation Station, ICAC 

Clean Air Technologies and Strategies, March 2005 
v 

Ex. 25: C. Erickson, S. Straight, and L. Hutcheson, Coal-Fired SCR Operating Experience with High 

Removal Efficiency and Low-NOx Firing Systems, 2003 

Ex. 26: T.R. Ake, C.A. Erickson, and L. K. Hutcheson, Increasing SCR NOx removal from 85% to 93% 

at the Duke Power Cliffside Steam Station, April 2006 ASME Power Division Special Section, 

ENERGY-TECH.com 

Ex. 27: S. Zwayyed, T. Pearson, and T. Reynolds, Low Maintenance SCR at the South Carolina Electric 

and Gas Cope Generating Station Unit 1, PowerGen 2009 

Ex. 28: Institute of Clean Air Companies, White Paper, Selective Catalytic Reduction (SCR) Control 

of NOx Emissions from Fossil Fuel-Fired Electric Power Plants, May 2009, EPA-R09-OAR2009-0598-0032 

Ex. 29: Texas Register, v. 26, no. 2, January 12, 2001, p. 557 

Ex. 30: B. Butler and R.P. Gaikwad, Operating Experience of SCRs at Texas Genco’s Coal and Gas 

Fired Plants, Mega Symposium, 2004 

Ex. 31: Texas Register, v. 26, no. 41, October 12, 2001, pp. 8159-8163 

Ex. 32: U.S. Environmental Protection Agency, Region 9, PSD Permit Issued Pursuant to Requirement 

at 40 CFR 52.21, PSD Permit Number AZP 04-01, Desert Rock Energy Company, July 31, 

2008 

Ex. 33: U.S. Environmental Protection Agency, Region 9, EPA Responses to Public Comments on the 

Proposed Prevention of Significant Deterioration Permit for the Desert Rock Energy Facility, 

July 31, 2008 

Ex. 34: Notes from October 16, 2007 U.S Environmental Protection Agency/Sithe Conference Call, 

Desert Rock Docket ID EPA-R09-OAR-2007-1110-0091 

Ex. 35: Georgia Department of Natural Resources, Air Quality Permit, Plant Washington, Permit 

No. 4911-303-0051P-010-0, April 8, 2010 

Ex. 36: Power4Georgians, LLC, Prevention of Significant Deterioration Air Permit Application, 

November 26, 2008, Supplemental Data, Exhibit A: Emission Calculations, Table A-2 

Ex. 37: Illinois EPA, Construction Permit – PSD Approval, NSPS Emission Units, Dallman Unit 4, 

August 10, 2006 

Ex. 38: Kansas Department of Health and Environment, Air Emission Source Construction Permit, 

Holcomb Station, December 16, 2010 

Ex. 39: Wyoming Department of Environmental Quality, Black Hills Corporation, Wygen 3, 

Permit No. CT-4517, February 5, 2007 

Ex. 40: Wyoming Department of Environmental Quality, Basin Electric Power Corp., Dry Fork 

Station, Permit No. CT-4631, October 15, 2007 

Ex. 41: Texas Department of Environmental Quality, Spruce Special Conditions, Permit Nos. 70492 

and PSD-TX-1037, June 28, 2005 

Ex. 42: Georgia Department of Natural Resources, Air Quality Permit No. 4911-099-0030-P-01-0, 

Longleaf Energy Associates, LLC, May 14, 2007 

Ex. 43: State of Nevada, Bureau of Pollution Control, Class I Air Quality Operating Permit, General 

Requirements, No. AP4911-1349, issued to Newmont Nevada Energy Investment, LLC, May 5, 

2005 

Ex. 44: Public Service Company of New Mexico, San Juan Generating Station, Best Available Retrofit 

Technology Analysis, prepared by Black & Veatch, June 6, 2007 
vi 

Ex. 45: Golder Associates, Inc., Air Construction Permit Application and Prevention of Significant 

Deterioration Analysis for FPL Glades Power Park, Glades County, Florida, Prepared for 

Florida Power & Light, December 2006, Table 2-1 

Ex. 46: Florida Power & Light Glades Response to EPA Comments, March 26, 2007 

Ex. 47: Matt Haber, Best Available Control Technologies for the Baldwin Generating Station, Baldwin, 

Illinois, Prepared for the United States in connection with: United States v. Illinois Power 

Company and Dynergy Midwest Generation, Inc., Civil Action No. 99-833-MJR, in the U.S. 

District Court for the Southern District of Illinois 

Ex. 48: BART Cost-effectiveness Summary 

Ex. 49: New Mexico Environment Department Air Quality Bureau, BART Determination, Public 

Service Company of New Mexico, San Juan Generating Station, Units 1-4, June 21, 2010 

Ex. 50: Letter from Andrew M. Gaydosh, Assistant Regional Administrator, EPA Region 8, to Terry 

O’Clair, Director, Division of Air Quality, North Dakota Department of Health, Re: EPA’s 

Comments on the North Dakota Department of Health’s April 2010 Draft BACT 

Determination for NOx for the Milton R. Young Station, May 10, 2010 

Ex. 51 – Ex 86: BACT Cost-effectiveness Documents 

Ex 87: U.S. Environmental Protection Agency, EPA Air Pollution Control Cost Manual, Report 

EPA/452/B-02-001, 6th Ed., January 2002 

Ex. 88: Four Corners Technical Support Document, Excel spreadsheet entitled “Four Corners SCR 

Cost Analysis 8-26-10,” from the Four Corners docket #EPA-R09-OAR-2010-0683 

Ex. 89: S.D. Unwin R.W. Johnson, S.W. Rudy, J.E. Delargey, and W. Rogers, Selective Catalytic 

Reduction (SCR) System Design and Operations: Quantitative Risk Analysis of Options, 

Presented at CCPS 17th Annual International Conference: Risk, Reliability, and Security 

Ex. 90: Thomas O’Brien, Email to Phil Hayes, EPSR, Dan Yagodinski, WPSC, Gary van Helvoirt, Greg 

Etvedt, WPSC, September 28, 2004, Re: 040928 SCR & SO2 Permitting Issues (revised) 

32.0440 

Ex. 91: Sargent & Lundy, Salt River Project, Najavo Generating Station – Units 1, 2, 3, SCR and 

Baghouse Capital Cost Estimate Report, August 17, 2010, Appendix A 

Ex. 92: U.S. Office of Management and Budget, Circular A-4, September 2003 

Ex. 93: IEA Clean Coal Centre, Selective Non-Catalytic Reduction (SNCR) for NOx Control 

Ex. 94: Nalco Mobotec, Multi-pollutant Emission Reduction Technology for Small Utility Boilers, 

Presented to Lake Michigan Air Directors Consortium, Innovative Industrial Source Control 

and Measurement Technologies Workshop, March 24, 2010 

Ex. 95: McIlvaine Utility Environmental Upgrade Tracking System, Reid Gardner Unit 4 

Ex. 96: Pfafflin J.R., Ziegler E.N. (eds.), Encyclopedia of Environmental Science and Engineering, Vol. 2, 

CRC Press, 2006 

Ex. 97: Black & Veatch, Platte River Power Authority, Rawhide Energy Station, Rawhide NOx 

Reduction Study 

Ex. 98: IEA Clean Coal Centre, Selective Non-Catalytic Reduction (SNCR) For NOx Control 

Ex. 99: U.S. Environmental Protection Agency, Identification of (and Responses to) Potential Effects of 

SCR and Wet Scrubbers on Submicron Particulate Emissions and Plume Characteristics, EPA600/R-04-107, August 2004 

Ex. 100: Nalco Mobotec, ROTAMIX® System 
vii 

Ex. 101: Nalco Mobotec, NOx Control 

Ex. 102: E.E. Haddad, J.S. Crilley, and B.S. Higgins, Mobotec USA Inc., The Viability and Economics of 

Adding a ROFA®/Rotamix® MobotecSystem to a Selective Catalytic Reduction (SCR) 

Installation, NETL/DOE 2003 Conference on SCR and SNCR for NOx Reduction, Pittsburgh, 

PA October 29-30, 2003 

Ex. 103: MobotecUSA, ROFA and ROTAMIX Installation, Cape Fear 6 of Progress Energy 

Ex. 104: G. Moberg, J.O. Blid, S. Wallin, T. Fareid, and J. Ralston, Combined DeNOx/DeSOx and 

Additional NOx Reduction by Cleaning Flue Gas Condensate From Ammonia, PowerGen 

International, November 30–December 2, New Orleans 1999 

Ex. 105: U.S. Environmental Protection Agency, Air Pollution Control Technology Fact Sheet, Name of 

Technology: Selective Non-Catalytic Reduction (SNCR), EPA-452/F-03-031 

Ex. 106: U.S. Environmental Protection Agency, Air Pollution Control Technology Fact Sheet, Name of 

Technology: Selective Catalytic Reduction (SCR), EPA-452/F-03-032 

Ex. 107: L.F. Drbal, P.G. Boston, K.L. Westra, Black & Veatch, Power Plant Engineering, Black & 

Veatch, Springer, 1996 

Ex. 108: California Air Resources Board, Compliance Assistance Technical Manual Series: Stationary 

Source Air Pollution Control Devices and Techniques, Section 309: Selective Catalytic 

Reduction Control Theory and Design 

Ex. 109: B. Adams and C. Senior, Curbing the Blue Plume: SO3 Formation and Mitigation, May 15, 2006 

Ex. 110: Chemithon, Enviro Safe Denox®, SafeDeNOx® Urea to Ammonia 

Ex. 111: CERAM, Project: IPALCO Harding St Unit 7, July 7, 2003 

Ex. 112: K.K. Humphreys and P. Wellman, Basic Cost Engineering, 3rd Ed., Marcel Dekker, Inc., 1996 

Ex. 113: Lamar Larrimore, Effects of Ammonia from Post-combustion NOx Control on Ash Handling 

and Use, Effects on Utilization Applications, Fuel Chemistry Division Preprints 2002, 

47(2), 832 

Ex. 114: Lewandowski, Boilers, Emission Controls and the CCPs They Generate, presented at the 

American Coal Ash Association Educational Program for Managers of Coal Combustion 

Products (CCP), Morgantown, WV, June 5-9, 2000

Ex. 115: ROFA and ROATMIX Installation, Cape Fear 6 of Progress Energy 

Ex. 116: ICAC, Typical Installation Timelines for NOx Emissions Control Technologies on Industrial 

 Sources, December 4, 2006. 
Comments 

 The federal Clean Air Act’s Regional Haze Rule requires assessment of older 

emission sources that are causing or contributing to visibility impairment in National 

Parks and Wilderness Areas (“Class I areas”) and installation of Best Available Retrofit 

Technology (“BART”) on BART-eligible sources.1 On November 2009, the Nevada 

Division of Environmental Protection (“NDEP”) adopted and transmitted the Nevada 

Regional Haze State Implementation Plan2 (“Nevada RH SIP”), which implements the 

requirements of the Regional Haze Rule, to EPA Region 9.3 On June 22, 2011, the 

U.S. Environmental Protection Agency (“EPA”) proposed to approve and promulgate a 

revision to the Nevada State Implementation Plan (“SIP”) to implement the regional 

haze program under the federal Clean Air Act for the first planning period through 

July 31, 2018 (“proposed rule”).4 

This comment letter addresses substantive flaws in EPA’s analysis of Nevada’s 

RH SIP and discusses how the proposed SIP revision fails to satisfy the requirements of 

the Regional Haze Rule under the federal Clean Air Act. Our comments focus mainly 

on the BART determinations for Nevada Energy’s Reid Gardner generating station but 

also address general flaws applicable to other BART-eligible sources in Nevada. 

I. EPA’s NOx BART Determinations for Reid Gardner Are 

Fundamentally Flawed 

Nevada Energy’s Reid Gardner generating station, located in Moapa, NV, is a 

primarily coal-fired steam-electric generating plant with four operating units. Units 1, 2, 

and 3, built in 1965, 1968, and 1976, respectively, are subject to BART requirements for 

reducing regional haze. Each of these units produces about 100 MW with wall-fired 

steam boilers manufactured by Foster Wheeler that drive turbine-generators firing 

primarily pulverized western bituminous coal. All three units are currently equipped 

with low NOx burners (“LNB”) and overfire air (“OFA”) systems for control of NOx; 

mechanical collectors and recently installed baghouses for particulate control; and wet 

scrubbers that use soda ash for sulfur dioxide (“SO2”) removal.5,6 

 

1 40 CFR 51 (64 FR 35174-35774). 

2 Nevada Division of Environmental Protection, Nevada Regional Haze State Implementation Plan, 

October 2009, EPA-R09-OAR-2011-0130-0003 (hereinafter “Nevada RH SIP”). 

3 76 FR 36451. 

4 76 FR 36450-36468. 

5 76 FR 36463. 

6 CH2MHill, BART Analysis for Reid Gardner Station Unit 1, 2, and 3, Prepared for NV Energy, Revised 

Report, October 2008, EPA-R09-OAR-2011-0130-0007 (hereinafter “10/08 CH2MHill BART Analyses”), 

pp. ES-3 and 2-1, respectively. 
2 

 The initial BART analyses for Reid Gardner Units 1-3 were prepared for Nevada 

Energy by the consulting company CH2MHill in October 2008. CH2MHill concluded 

that BART for NOx for Reid Gardner was satisfied by LNB with OFA designed to meet 

a NOx emission limit of 0.39 lb/MMBtu at Units 1 and 2 and 0.46 lb/MMBtu at Unit 3.7

NDEP adopted the company’s cost analysis as presented in the 10/08 CH2MHill BART 

Analyses but used different baseline years for uncontrolled NOx emission rates based 

on the acid rain database maintained by EPA’s Clean Air Markets Division (“CAMD”).8

Table 1 summarizes the baseline (pre-BART) NOx emission rates for Reid Gardner and 

control scenarios evaluated by NDEP for its BART determinations. 

Table 1: 

Baseline years, baseline (pre-BART) NOx emission rates, 

and NOx control efficiency for control scenarios evaluated by NDEP for Reid Gardner 

 Unit 1 Unit 2 Unit 3

Baseline yearsa 2002/2003 2002/2003 2001/2002 

Baseline (pre-BART) NOx emission rate (lb/MMBtu)b 0.461 0.462 0.447 

NOx control efficiency (%)c 

(1) LNB/OFA 21.3 23.7 6.5 

(2) LNB/OFA and SNCR 40.9 42.7 29.9 

(3) ROFA with Rotamix 57.7 59.0 38.3 

(4) LNB/OFA with SCR 81.6 82.2 78.2 

(5) ROFA with SCR 81.6 82.2 78.2 

a 10/22/09 10/22/09 NDEP BART Review, p. 6: two consecutive years from 2001 through 2007 with highest NOx emission 

rates 

b Average of EPA’s CAMD data NOx emission rates for two baseline years 

c 10/22/09 NDEP BART Review, Table 1, pp. 5-6 

NDEP determined that BART is rotating opposed overfire air (“ROFA”) with 

Rotamix and emission limits of 0.20 pounds per million British thermal units 

(“lb/MMBtu”) for Units 1 and 2 and 0.28 lb/MMBtu for Unit 3 based on a 12-month 

rolling average.9 The EPA is proposing to approve these BART determinations.10 This 

does not satisfy BART for the subject units at Reid Gardner for the reasons discussed in 

detail below. Instead, BART for these units should be the use of low NOx burners 

 

7 10/08 CH2MHill BART Analyses, pp. ES-3 and 2-1, respectively. 

8 Nevada Division of Environmental Protection, BART Determination Review of NV Energy’s Reid 

Gardner Generating Station Units 1, 2, and 3, Revised October 22, 2009, EPA-R09-OAR-2011-0130-0003, 

(hereinafter “10/22/09 NDEP BART Review”), p. 6. 

9 Ibid., Table 1. 

10 76 FR 36463. 
3 

(“LNB”) with overfire air (“OFA”) and a selective catalytic reduction (“SCR”) system 

designed to reduce NOx emissions to 0.05 lb/MMBtu on a 30-day rolling average based 

on a boiler operating day and an ammonia slip11 of 2 parts per million (“ppm”)12. The 

basis of this conclusion is set out below. 

Best Available Retrofit Technology or BART is “an emission limitation based on 

the degree of reduction achievable through the application of the best system of 

continuous emission reduction...”13 BART is determined on a case-by-case basis 

following a five-step process laid out in the BART Guidelines, as follows: 

STEP 1 – Identify all available retrofit control technologies 

STEP 2 – Eliminate technically infeasible options 

STEP 3 – Evaluate control effectiveness of remaining control technologies, 

STEP 4 – Evaluate impacts and document the results, and 

STEP 5 – Evaluate visibility impacts.14

 

 The BART analyses conducted by CH2MHill and NDEP contain a number of 

fatal flaws in implementing Steps 3 and 4 of this process. 

I.A NDEP’s NOx BART Determination for Reid Gardner Failed to 

Evaluate the Most Stringent NOx Emission Control Level for SCR 

 Many of the NOx control options that were evaluated are capable of performing 

at a wide range of levels. A selective catalytic reduction (“SCR”) system, for example, 

can remove 90% or more of the NOx emissions.15 A selective non-catalytic reduction 

system (“SNCR”) typically removes 30% to 60% of the NOx, depending upon the 

specifics of the boiler.16 The EPA’s BART Guidelines, which EPA claims NDEP 

followed17, notes: “It is important, however, that in analyzing the technology you take 

 

11 Unreacted ammonia from an SCR or SNCR emitted from the stack is commonly called ammonia slip. 

12 See, for example, Environmental Protection Agency, 40 CFR Part 52, [EPA-R06-OAR-2010-0846; FRL- ], 

Approval and Promulgation of Implementation Plans; New Mexico; Federal Implementation Plan for 

Interstate Transport of Pollution Affecting Visibility and Best Available Retrofit Technology 

Determination, signed by L.P. Jackson, dated August 4, 2011 (hereinafter “New Mexico FIP”) and 

supporting Technical Support Document, (Exhibit 1). 

13 40 CFR 51.301. 

14 70 FR 39164. 

15 California Air Resources Board, Compliance Assistance Technical Manual Series: Stationary Source Air 

Pollution Control Devices and Techniques, Section 310: Selective Non-Catalytic Reduction Control 

Theory and Design; http://www.arb.ca.gov/cap/manuals/cntrldev/sncr_etc/310sncr.htm, accessed 

August 19, 2011 (Exhibit 2). 

16 Ibid. 

17 76 FR 36462, see also Comment II.B. 
4 

into account the most stringent emission control level that the technology is capable of 

achieving.” Elsewhere, the BART Guidelines note: “While you must consider the most 

stringent level as one of the control options, you may consider less stringent levels of 

control as additional options.”18 This was not done. As demonstrated below, the BART 

analysis was not based on the most stringent level of control that could be reasonably 

achieved by either the selected BART technology, ROFA/Rotamix, or the technology 

that should have been selected, SCR with LNB/OFA. 

 NDEP (and CH2MHill) considered two control scenarios with SCR systems: 

ROFA with SCR (option 4) and LNB/OFA with SCR (option 5). NDEP reported the 

combined control efficiency for these two scenarios as 81.6% for Unit 1, 82.2% for Unit 2, 

and 78.2%, for Unit 3.19 However, a portion of this reduction is due to the ROFA in 

option 4 and to the LNB/OFA in option 5. The NDEP does not disclose the portion of 

this reduction due to ROFA, but does disclose it for the LNB/OFA.20 Using NDEP’s 

information, the cost analyses for LNB/OFA with SCR at Units 1 to 3 assume that the 

SCR system would remove only 77% of the NOx at the inlet to the SCR.21 

As BART is “an emission limitation based on the degree of reduction achievable 

through the application of the best system of continuous emission reduction...,” it is 

essential to consider “the most stringent emission control level” in evaluating control 

effectiveness. The NDEP BART determination did not even identify, let alone consider, 

the most stringent emission control level that SCR systems are capable of achieving. 

When the most stringent emission control level is not considered, the BART Guidelines 

require “a showing of differences between the source and other sources that have 

achieved more stringent emissions limits...”22 The record in this case contains no 

showing of differences between Reid Gardner Units 1, 2, and 3 and many other similar 

sources that have been permitted and are currently operating with SCRs designed to 

remove 90% or more of the units’ NOx emissions with outlet NOx levels as low as or 

lower than 0.05 lb/MMBtu based on a 30-day rolling average. 

 

18 70 FR 39166, emphasis added. 

19 10/22/09 NDEP BART Review, Table 1, pp. 3 and 5-6; see also 10/09 CH2MHill BART Analyses, 

Table 3-2, p. 3-8, respectively. 

20 10/22/09 NDEP BART Review, p. 3 and Table 1. 

21 Based on 10/22/09 NDEP BART Review, Table 1, the assumed SCR removal efficiency based on the 

controlled NOx emission rates (in lb/MMBtu) for Unit 1: (1-0.085/0.364) = 0.766; Unit 2: (1-0.083/0.355) = 

0.766; Unit 3: (1-0.098/0.421) = 0.767. 

22 70 FR 39166. 
5 

I.A.1 SCR Can Meet an Emission Limit of 0.05 lb/MMBtu NOx and 

≥90% Control Efficiency 

The control efficiencies assumed for SCR options at Reid Gardner Units 1-3 

(81.6%, 82.2%, 78.2%, respectively) are considerably lower than typically guaranteed by 

vendors for coal-fired boilers. CH2MHill’s reports claim that the design control 

efficiencies were based on vendor-obtained performance quotations.23 These vendorobtained performance quotations or the request for proposal that they are based on are 

not provided anywhere in the record. Do the control efficiencies that were costed, for 

example, represent the best level of reduction that can be achieved, or are they just the 

levels requested by CH2MHill? The record is silent on this key issue. Neither EPA nor 

NDEP questioned these unusually low control efficiencies but instead took them at face 

value. 

An SCR system by itself (i.e., without LNB /OFA or ROFA) is routinely designed 

to achieve 90% NOx reduction. There is nothing unusual about Reid Gardner that 

would preclude the installation and operation of a 90% efficient SCR. The NOx emission 

rates that could be achieved at Reid Gardner using a 90% efficient SCR are summarized 

in Table 2. 

Table 2: 

Achievable controlled NOx emission rates at Reid Gardner 

based on NDEP baseline and SCR with 90% control efficiency 

Unit 

Baseline 

yearsa 

NDEP baseline 

emission ratesb

Controlled NOx 

emission ratesc 

(lb/MMBtu) (lb/MMBtu) 

1 2002/2003 0.461 0.04605 

2 2002/2003 0.462 0.04615 

3 2001/2002 0.447 0.04465 

a 10/22/09 10/22/09 NDEP BART Review, p. 6: two consecutive years from 2001 through 

2007 with highest NOx emission rates 

b Average of EPA’s CAMD data NOx emission rates for two baseline years 

c (NDEP baseline emission rates) × (1-0.90) 

It is reasonable to assume a NOx emission limit of 0.05 lb/MMBtu and 90% NOx 

control by SCR for Reid Gardner, given the impressive and growing track record of 

successful SCR installations documented below, over 300 in operation in the United 

States alone, and the low sulfur content of the coal fired at Reid Gardner (0.29%-0.57%). 

These SCRs have been installed on electric generating units ranging in size from 40 MW 

to over 1600 MW. The San Juan units are 100 MW each. The Reid Gardner units could 

be controlled by three 100-MW SCR systems, or the three units ducted together and 

 

23 10/08 CH2MHill BART Analyses, p. 3-7, respectively. 
6 

served by a single 300-MW system. The Energy Information Agency database, Form 

EIA-860, indicates that 353 EGUs are retrofit with SCR and that of these, 37 are 100 MW 

or smaller and 146 are 300 MW or smaller. 

The EPA must demonstrate why SCR at Reid Gardner cannot achieve 90% NOx 

control when SCR retrofits on older boilers are doing much better today. The docket 

contains no site-specific or technical factors that would preclude the successful 

installation and operation of a 90% efficient SCR at Reid Gardner. 

a) General SCR Design Experience 

It is widely recognized today that all major SCR catalyst vendors24 can easily 

guarantee at least 90% efficiency for SCRs burning coals with a wide range of 

properties, from low sulfur, highly alkaline ash, high moisture Powder River Basin 

(“PRB”) subbituminous coal to high sulfur, high ash, high moisture lignites to high 

sulfur, high ash, bituminous coal and coal waste. Vendor experience lists25 indicate that 

SCRs are routinely designed for 90% NOx control, depending on purchaser 

specifications. The NOx design efficiencies of retrofit SCRs in the CAMD database and 

the ICAC White Paper were compiled from publicly available sources and are 

summarized in Attachment 2. This summary shows that SCR NOx control efficiencies 

were available for 242 out of 372 coal-fired boilers equipped with SCR units. Of these, 

188 or 78% were designed for 90% or greater NOx control efficiency on a wide range of 

coals. 

Most of these SCRs are required under various trading programs that cap 

regional or utility-wide emissions, allowing the operator to evaluate market conditions 

to determine whether to operate existing controls, install more controls, or purchase 

allowances generated by other plants. This allows significant flexibility in operation of 

any given SCR. Thus, most of the SCR-controlled units do not operate at design 

efficiencies all of the time as they do not have unit-specific NOx permit limits. 

Reflecting on this experience in 2003, Sargent and Lundy, an engineering firm 

that designs SCRs, stated: 

“[A]ll Sargent & Lundy-designed SCR reactors at coal-fired units, which have been 

placed into service, have achieved their guaranteed NOx reduction efficiencies within 

the specified ammonia slip limits. The minimum design NOx reduction efficiency was 

 

24 These include Haldor Topsoe (Exhibit 3), Hitachi (Exhibit 4), Johnson-Matthey/Argillon (Exhibit 5), 

CERAM (Exhibit 6), etc. 

25 See, e.g., Haldor Topsoe, SCR Experience List, October 2009 (Exhibit 3), Hitachi, NOx Removal Coal 

Plant Supply List, October 17, 2006 (Exhibit 4); Argillon Experience List U.S. Coal Plants (Exhibit 5); 

Hitachi, SCR System and NOx Catalyst Experience, Coal, February 2010 (Exhibit 7). 
7 

85% and the maximum reduction efficiency was in excess of 90%. Design ammonia slip 

levels ranged between 2 ppm and 3 ppm at the end of catalyst life. Although no SCR 

installations have yet operated for the guaranteed catalyst life duration, it is anticipated 

that the NOx reduction and ammonia slip performance guarantees will continue to be 

met over that period. Operational installations include pulverized coal units burning 

PRB coal, Illinois low- to high-sulfur coal, and eastern low to high-sulfur coal; one 

cyclone unit burning PRB coal; and two cyclone units burning Illinois low-sulfur coal. 

SCR reactor designs have included 2+1 and 3+1 catalyst level installation sequences and 

have used plate, honeycomb, and corrugated type catalysts. Design of SCR reactors for 

removal efficiencies greater than 90% at ammonia slip levels less than 2 ppm to 3 ppm 

has been demonstrated and should be considered as a feasible design criterion.”26

Cormetech, an SCR catalyst vendor noted the following in a 2007 paper: 

“It is common for units to be designed for NOx removal efficiencies of 90%, and operate 

at efficiencies that are greater than the design value. As catalyst performance guarantees 

are defined to be those associated with the end of a specified lifetime, SCR catalyst that 

is early in its functional life has considerably higher capability. As an example, catalyst 

that is designed to achieve 90% NOx removal and 2 ppm ammonia slip after a lifetime of 

24,000 operating hours will operate with virtually no ammonia slip at the beginning of 

its life.”27 

Siemens AG, another catalyst supplier notes: 

“Selective Catalytic Reduction (SCR) is currently the most widely applied state of the art 

technology for controlling NOx emissions from coal fired power plants... across 

Germany, many other parts of Europe, in Japan, as well as in the US. This technology 

has been proven to be reliable over almost two decades of use under the most extreme 

conditions. SCR can reduce NOx emissions up to >93% in many cases...”28

 

26 Kurtides, T., Sargent and Lundy, Lessons Learned from SCR Reactor Retrofit, COAL-GEN, Columbus, 

OH, August 6-8, 2003; 

http://www.adeq.state.ar.us/ftproot/pub/commission/p/Closed%20Permit%20Dockets%202006-

2010/08-007-P%20AEP%20Service%20Corp%20&%20SwepcoHempstead%20Co%20Hunting%20Club/2008-12-

03_Ex._7_SCR_Lessons_Learned_from_SCR_Reactor_Retrofit_Coal-G.pdf, accessed August 18, 2011 

(Exhibit 8). 

27 Rutherford, S., Coal-Fired SCR Applications in the US – Challenges and Strategies for Successful 

Operation and Emission Compliance, Cormetech Inc., VGB Workshop “Flue Gas Cleaning 2007,” Vienna, 

Austria, May 22–23, 2007; http://www.cormetech.com/brochures/2007_VGB_Conference_Paper.pdf, 

accessed August 18, 2011 (Exhibit 9). 

28 Karina Rigby and others, SCR: The Most Effective Technology for NOx Reduction in Large Combustion 

Plants; http://legsys.infomil.nl/legsys/noxconf/uk/pdf/combust/rigby.pdf, accessed August 18, 2011 

(Exhibit 10). 
8 

Hitachi’s NOx Removal Coal Plant Supply List also includes many retrofit SCRs 

on similar existing units that burn similar and more difficult fuels that were designed to 

achieve 90% NOx reduction.29

In a paper discussing developments in China, Haldor Topsoe, a SCR catalyst 

vendor, stated that “[T]he Taishan Thermal Power Plant is a 5 × 600 MWe coal-fired 

power plant firing domestic coals. Unit 5 includes an SCR system, scheduled for startup in 2006. Haldor Topsøe A/S is the supplier of the catalyst and critical components 

and has performed the system design including physical flow model tests. The DeNOx 

unit is guaranteed to have a NOx conversion at 94% with only 3 ppm ammonia slip.”30 

b) General Operating Experience in U.S. 

Continuous emission monitoring data submitted by utilities to EPA’s CAMD and 

analyzed by others indicate that “90% removal efficiency is currently being achieved by 

a significant portion of the coal-fired SCR fleet.”31 More than 30 units have achieved 

greater than 90% NOx reduction.32 NOx removal of 90% was achieved on 10,000 MW of 

coal-fired generation in 2004. The McIlvaine Reports, a source of control technology 

information for BACT determination, reported that three of Haldor Topsoe’s SCR 

installations averaged over 95% NOx reduction during the 2005 ozone season.33

Similarly, the U.S. EPA analyzed CAMD NOx data for 22 existing units that are 

achieving limits below 0.07 lb/MMBtu on a 30-day rolling average. Eight of these units 

were operating at or above 90% removal efficiency and not one was operating at less 

than 86%.34 Moreover, these data were collected from 2003, before the NOx SIP Call35

 

29 Hitachi, NOx Removal Coal Plant Supply List, October 17, 2006 (Exhibit 4). 

30 H. Jensen-Holm, N.-Y. Topsøe, J.J. Cui, Implementation of SCR DeNOx Technology on Coal-Fired 

Boilers in P.R. China, Haldor Topsoe, August 2006; 

http://www.topsoe.com/business_areas/air_pollution_control/~/media/PDF%20files/Scr_denox/Imp

lementation%20of%20SCR%20techology%20on%20Coal%20Fired%20Boilers%20%20China%20Power%20

2006.ashx, accessed August 19, 2011 (Exhibit 11). 

31 James E. Staudt and Clayton Erickson. Selective Catalytic Reduction System Performance and 

Reliability Review, Andover Technology Partners, p. 15; 

http://www.gaepd.org/air/airpermit/downloads/permits/psd/dockets/longleaf/appealdocs/exhibits

/excluded/Petitioners/P-006-1.pdf, accessed August 18, 2011 (Exhibit 12). 

32 Ibid, p. 1. 

33 McIlvaine, Utility E-Alert #798, November 3, 2006 (Exhibit 13). 

34 Srivastava et al., Nitrogen Oxides Emission Control Options for Coal-Fired Electric Utility Boilers, J. Air 

& Waste Manage. Assoc., Vol 55, pp. 1367-1388, Table 4; 

http://www.netl.doe.gov/technologies/coalpower/ewr/pubs/NOx%20control%20Lani%20AWMA%20

0905.pdf (Exhibit 14). 

35 In October 1998, EPA finalized the “Finding of Significant Contribution and Rulemaking for Certain 

States in the Ozone Transport Assessment Group Region for Purposes of Reducing Regional Transport of 
9 

and other regulatory programs for NOX were in place. Because compliance with the 

NOx SIP Call was generally not required until May of 2005, performance has improved 

since then compared to 2003.36 A recent reanalysis of CAMD data by EPA indicates 

“many boilers retrofitted with SCR are achieving an emission rate of 

0.03-0.06 lb/MMBtu.”37

SCR system designers have analyzed EPA CAMD CEMS data to determine the 

NOx levels that are currently being achieved by over 100 SCR-equipped coal-fired 

boilers. This analysis identified 25 units that are achieving NOx emissions less than 

0.05 lb/MMBtu on an hourly average basis.38 Others have reported similar results.39

A few examples of retrofit units designed for 90% NOx control are discussed below. 

c) Specific SCR Design with NOx Control Efficiency of ≥90% and 

Operating Experience 

This section reviews the design basis of several coal-fired boiler retrofit units. 

The subject Reid Gardner BART units could be designed to meet the same design basis 

as the units discussed below, i.e., ≥90% NOx control with low SO2 to SO3 conversion 

and low ammonia slip. While these and other SCRs are routinely designed to achieve 

90% NOx control, they may not be not operated to meet these design targets as they 

operate under cap and trade programs that do not apply to specific units. This 

discrepancy between design and operation is discussed in the next section and does not 

affect the NOx BART determination. 

Vendor acceptance tests indicate that units designed to achieve 90%+ NOx 

reduction are able to meet and often exceed the design levels. When the need arises, the 

SCRs are able to perform as designed. This has been demonstrated in many cases. The 

 

Ozone,”commonly called the “NOx SIP Call.” The NOx SIP Call was designed to mitigate significant 

transport of NOx, one of the precursors of ozone; see U.S. Environmental Protection Agency, The NOx SIP 

Call; http://www.epa.gov/airmarkets/progsregs/nox/noxsipcall.html, accessed August 18, 2011. 

36 M.J. Oliva and S.R. Khan, Performance Analysis of SCR Installations on Coal-Fired Boilers, Pittsburgh 

Coal Conference, September 2005, p. 3; 

http://www.gaepd.org/air/airpermit/downloads/permits/psd/dockets/longleaf/appealdocs/exhibits

/excluded/Petitioners/P-013.pdf, accessed August 18, 2011 (Exhibit 15). 

37 Callie A. Videtich, Director Air Program, EPA Region 8, Letter to Paul Tourangeau, Director, Colorado 

Department of Public Health and the Environment, Re: Regional Haze State Implementation Plan, 

October 26, 2010, p. 3 (Exhibit 16). 

38 Clay Erickson, Robert Lisauskas, and Anthony Licata, What’s New in SCRs, DOE’s Environmental 

Control Conference, May 16, 2006, p. 28; 

http://www.netl.doe.gov/publications/proceedings/06/ecc/pdfs/Licata.pdf, accessed August 18, 2011 

(Exhibit 17). 

39 M.J. Oliva and S.R. Kahn, Performance Analysis of SCR Installations on Coal-Fired Boilers, Presented at 

the Pittsburgh Coal Conference, September 2005 (Exhibit 15). 
10 

W.A. Parish Electric Generating Station units, for example, operate under the HoustonGalveston-Brazoria ozone nonattainment area regulations. (See Comment I.A.1.e). 

Parish Unit 8, which typically operates at about 0.044 lb/MMBtu, was run for extended 

periods at 0.03 lb/MMBtu and then at 0.035 lb/MMBtu (August through November 

2006) to demonstrate its capability to do so.40 

i. Seminole Units 1 & 2 

The Seminole Generating Station consists of two 650 MW units firing eastern 

bituminous coal.41 The Seminole SCR systems were designed for 90% NOx reduction 

and low SO2 conversion (<0.5%). The inlet NOx (0.413 lb/MMBtu) and controlled with 

LNB and OFA (uncontrolled NOx emissions Unit 1: 0.461 lb/MMBtu, Unit 2: 0.462 

lb/MMBtu, Unit 3: 0.447 lb/MMBtu).42 The design basis for the Seminole SCRs is given 

in Table 3. The required outlet NOx of 0.04 lb/MMBtu represents the end-of-life 

performance after catalyst deactivation has taken place.43 

Table 3: 

Design criteria for Seminole Units 1 and a

a from W.J. Gretta, D. Harajda, A.C. Favale, and T.J. Wess, The SCR Retrofit 

Design for the Seminole Generating Station; 

http://www.hitachipowersystems.us/supportingdocs/forbus/hpsa/technical_papers/

SCR_Retrofit_Seminole_Generating_Station.pdf, accessed August 18, 2011, 

attached as Exhibit 19 

Performance testing indicated the installed SCR systems significantly 

outperformed their NOx removal guarantees of 90.3%, from 0.413 lb/MMBtu to 

 

40 B. Butler and R.P. Gaikwad, Operating Experience of SCRs at Texas Genco’s Coal and Gas Fired Power 

Plants, Mega Symposium 2004 (Exhibit 19). 

41 W.J. Gretta, D. Harajda, A.C. Favale, and T.J. Wess, The SCR Retrofit Design for the Seminole 

Generating Station; 

http://www.hitachipowersystems.us/supportingdocs/forbus/hpsa/technical_papers/SCR_Retrofit_Se

minole_Generating_Station.pdf, accessed August 18, 2011 (Exhibit 19). 

42 Email from Andrew Gray to Petra Pless, Re: NDEP Spreadsheets, August 20, 2011, and Excel 

spreadsheet ‘Copy Acid Rain Annual Data BART NVE (4).xls’ provided via email by Adele Malone, 

NDEP, to Andrew Gray, Gray Sky Solutions, on August 11, 2011 (Exhibit 20). 

43 W.J. Gretta et al. (Exhibit 19). 
11 

0.04 lb/MMBtu. Ammonia slip, guaranteed at 2 ppm, was measured at 0.2 ppm. The 

SO2 oxidation was guaranteed at 0.5% and measured at less than 0.1% across the entire 

SCR system. The system pressure drop was less than 5 inches of water, well under the 

guaranteed value.44 

ii. Morgantown Generating Station Units 1 & 2 

 The Morgantown 642 MW boilers burn high sulfur (3%) eastern bituminous coal. 

An SCR was installed in 2007/2008, designed to remove 92.5% from an inlet NOx of 

0.6 lb/MMBtu at maximum load to an outlet of 0.045 lb/MMBtu and an SO2 oxidation 

rate of 0.5% and 2 ppm ammonia slip. The SCR consists of two four-layer reactors per 

unit, with three initially installed layers and one future layer of catalyst. The acceptance 

test demonstrated 92.65% to 94.6% NOx removal to outlets of 0.032 lb/MMBtu at 

maximum load and 90% to 91.3% at minimum load to NOx outlets of 0.043 to 

0.054 lb/MMBtu.45 

iii. Louisville Gas & Electric (E.ON) Program Alliance 

 Louisville Gas & Electric (“LGE,” now E.ON) retained Babcock Power and Duke 

Fluor Daniel to engineer, procure, and construct six SCRs within the LG&E system. The 

first was Trimble County Generating Station Unit 1 (tangentially fired 547 MW), 

followed by similar projects at Mill Creek Generating Station Unit 3 (opposed wall fired 

410 MW); Mill Creek Generating Station 4 (opposed wall fired 520 MW); Ghent 

Generating Station Units 3 and 4 (opposed wall fired 520 MW); and Ghent Generating 

Station Unit 1 (tangentially fired 520 MW). Each SCR system was designed to reduce 

baseline NOx emissions by 90%. These systems included a variety of boilers, operating 

conditions, space restrictions, low and high dust loadings, low and high sulfur coals, 

various coal blends, and inlet NOx ranging from 0.34 to 0.45 lb/MMBtu. The acceptance 

tests indicate that all systems met or exceeded design requirements.46 

Detailed results have been published for one of the units, Trimble County 

Generating Station Unit 1, which fires high sulfur (~4%) eastern bituminous coal. The 

 

44 R. Peltier, Top Plants: Seminole Generating Station, Palatka, Florida, Power, October 1, 2009; 

http://www.powermag.com/coal/Top-Plants-Seminole-Generating-Station-PalatkaFlorida_2181_p4.html, accessed August 18, 2011 (Exhibit 21). 

45 K. Bresnahan, C. Erickson, M. Phillipo, S. Dean, and B. Rogan, Design, Installation and Startup 

Experience on a High Removal Efficiency SCR System at Morgantown Generating Station Units 1&2, 

Mega 2008; http://secure.awma.org/presentations/Mega08/presentations/5-Erickson.pdf, accessed 

August 18, 2011 (Exhibit 22). 

46 E. Saunders, S. Straight, E. Pear, C. Erickson, H. Culberson, and M. Kelly, SCR System Performance at 

LG&E’s Trimble County Generating Station, EPRI Workshop on Selective Catalytic Reduction, 

Atlanta, GA, October 22-23, 2002; www.babcockpower.com/pdf/t-177.pdf, accessed August 18, 2011 

(Exhibit 23). 
12 

SCR was designed to reduce NOx from 0.32 lb/MMBtu by 90% to 0.032 lb/MMBtu with 

2 ppm ammonia slip and an SO2 to SO3 conversion of 1.5%. These units were designed 

and installed before low SO2 conversion catalyst had been developed.47 Trimble was a 

difficult retrofit application with space restrictions and a high sulfur fuel. 48 The 

acceptance testing, which occurred in September 2002, yielded the results summarized 

in Table 4. 

Table 4: 

Trimble County acceptance test resultsa 

a C. Erickson, S. Straight, and L. Hutcheson, Coal-Fired SCR Operating Experience with High Removal Efficiency 

and Low-NOx Firing Systems, 2003; http://www.babcockpower.com/pdf/t-188.pdf, accessed August 18, 2011, 

attached as Exhibit 25 

This work concluded: “Based on Riley Power Inc. analysis and industry 

experience... mixing systems with <3% standard deviation can obtain ultra high NOx 

removal efficiencies of >93% with the correct catalyst volume.”49

iv. Cliffside Unit 5 

An 85% efficient SCR was originally installed on Duke Energy’s 590 MW 

Cliffside Steam Station Unit 5 in May 2002. The unit burns 1.5% Central Appalachian 

bituminous coal. This unit was upgraded in 2003 to meet the NOx SIP Call limit during 

the ozone season. The demonstration test indicate: “[T]he SCR system for the Unit 5 

boiler at the Cliffside steam station operated at 93% NOx removal with the ammonia to 

NOx ratio variation within 5% for each reactor. While the SCR is not currently operated 

at this high NOx removal rate, the test results showed that the SCR is able to operate at 

 

47 J. Cooper, W.J. Gretta, A.C. Favale, and H.N. Franklin, First Application of Babcock-Hitachi K.K. Low 

SO2 to SO3 Oxidation Catalyst at the IPL Petersburg Generation Station, ICAC Clean Air Technologies 

and Strategies, March 2005; 

http://www.hitachipowersystems.us/supportingdocs/forbus/hpsa/technical_papers/ICAC2005.pdf, 

accessed August 18, 2011 (Exhibit 24). 

48 E. Saunders et al. (Exhibit 23). 

49 C. Erickson et al. (Exhibit 25). 
13 

high NOx removal without added risk to the catalyst or causing excessive 

ammonia slip.”50

v. Cope Generating Station 

 The SCE&G 400 MW Cope Generating Station burns bituminous coal. The SCR 

was designed to reduce the NOx from an outlet of 0.32 lb/MMBtu to 0.032 lb/MMBtu 

based on 90% NOx reduction. The guaranteed SO2 oxidation was 1% at 688 F. The 

performance tests demonstrated NOx removal at 91.6% with an average SO2/SO3

oxidation rate of 0.3%.51

d) SCR Experience with Boiler Retrofits in the United States 

The Institute of Clean Air Companies (“ICAC”) May 2009 White Paper on SCR52

compiled information showing that over 300 SCR systems have been installed on coal 

fired-boilers in the U.S.53 to meet various regulatory programs.54 Most of the SCRs on 

coal-fired boilers are designed for about 90% NOx removal.55 About a third or 118 of 

these SCRs serve units 300 MW and lower in output. Ten SCR system included in this 

summary operate on boilers that are 100 MW or under. (See Attachment 2.) The size of 

the boiler does not affect the performance of SCR. 

These SCRs are individually listed in the ICAC White Paper.56 Over 95% of these 

listed SCRs were installed on existing facilities as retrofit applications, indicating that 

that 90% or greater NOx removal is routine for retrofit units such as Reid Gardner. This 

is supported by information compiled from EPA’s CAMD, which reports the year each 

boiler was installed and its controls. This analysis, attached as Attachment 257, shows 

that almost all of the existing SCRs, 94% of those included in the CAMD database, were 

installed on units that were built before the first SCR was installed in the U.S. in 1994. 

 

50 T.R. Ake, C.A. Erickson, and L. K. Hutcheson, Increasing SCR NOx removal from 85% to 93% at the 

Duke Power Cliffside Steam Station, April 2006 ASME Power Division Special Section, ENERGYTECH.com, www.babcockpower.com/pdf/rpi-13.pdf, accessed August 19, 2011 (Exhibit 26). 

51 S. Zwayyed, T. Pearson, and T. Reynolds, Low Maintenance SCR at the South Carolina Electric and Gas 

Cope Generating Station Unit 1, PowerGen 2009 (Exhibit 27). 

52 Institute of Clean Air Companies, White Paper, Selective Catalytic Reduction (SCR) Control of NOx 

Emissions from Fossil Fuel-Fired Electric Power Plants, May 2009, EPA-R09-OAR-2009-0598-0032, 

(hereinafter “ICAC 2009 White Paper on SCR”) (Exhibit 28). 

53 Ibid., p. 7. 

54 Ibid., pp. 4-5. 

55 Ibid., pp. 7 and 12. 

56 Ibid., pp. 23-29. 

57 Information compiled from EPA’s CAMD database, which reports the year each boiler was installed 

and its controls. 
14 

And of these, the majority (84%) are installed on pre-New Source Performance Standard 

(“NSPS”) units that were built prior to 1978. A further compilation of SCR control 

efficiency data from vendor experience lists, technical papers, and McIlvaine databases 

(Attachment 3) shows that SCR design NOx control efficiency has increased over time, 

from around 50% on the first units in the 1990s to 90%+ on SCRs designed from 2000 

onward. Thus, the existing installed SCR base is retrofit SCRs. The majority of these 

retrofitted units operate under various trading programs without permit limits and they 

are not obligated to meet any specific NOx emission limit 

Further, the ICAC report notes that SCRs are being designed to achieve NOx 

emission rates of 0.04 lb/MMBtu58, substantially lower than the 0.083–0.098 lb/MMBtu 

established by NDEP as controlled emission levels for Reid Gardner Units 1-3.59 In most 

instances, a retrofit SCR can achieve the same NOx reduction efficiency as an SCR on a 

new facility. The catalyst and the rest of the SCR system starts out new in both cases 

and treats the exhaust gas from the same coal. The only retrofit exception would be the 

lack of adequate space to optimize ductwork layout to achieve adequate mixing of 

ammonia with the flue gas. CH2MHill’s BART Analyses for Reid Gardner Units 1-3 

indicate no such limitation and this issue has not been raised in the docket. Even if it 

existed, it could be addressed by locating the SCR at the tail end of the plant. 

e) Existing SIP BART Emission Limits 

EPA’s BART Guidelines require permitting agencies to “consider recent 

regulatory decisions... when identifying an emissions performance level” that can be 

achieved by available pollution-reduction methods.60 

 The Texas Commission concluded in 2001 that a NOx emission limit of 

0.03 lb/MMBtu was “technically feasible in the commission’s analysis, based on the 

literature and discussion with SCR vendors. REI [Reliant Energy Inc., now NRG, owner 

of the Texas Parish units] has awarded a contract for construction of SCRs on its four 

coal-fired boilers with an emission specification of 0.03 lb NOx/MMBtu, which 

supports the commission’s view that the technology has the capacity to achieve this 

level.”61 The Commission then established emission limits of 0.033 lb/MMBtu for the 

Dallas/Fort Worth nonattainment area and 0.040 lb/MMBtu for the 

Houston/Galveston nonattainment area for coal-fired boilers.62 

 

58 Ibid., p. 7. 

59 10/22/09 NDEP BART Review, pp. 5-6. 

60 70 FR 39166 (July 6, 2005). 

61 Texas Register, v. 26, no. 2, January 12, 2001, p. 557 (Exhibit 29). See also: B. Butler and R.P. Gaikwad, 

Operating Experience of SCRs at Texas Genco’s Coal and Gas Fired Plants, Mega Symposium, 2004 

(Exhibit 30). 

62 Texas Register, v. 26, no. 41, October 12, 2001, pp. 8159-8163, (Exhibit 31). 
15 

These limits were subsequently modified and incorporated into the Texas SIP 

under a cap and trade program. The current ozone SIP for the Houston-GalvestonBrazoria area specifies NOx emission limits for wall-fired units of 0.05 lb/MMBtu and 

for tangential-fired boilers of 0.045 lb/MMBtu, based on daily and 30-day averaging 

periods.63 The Texas SIP limit for wall-fired boilers, expressed as both a daily and 

30-day average, is lower than the BART limit we recommend for each of the three wallfired Reid Gardner units (0.05 lb/MMBtu). The docket contains no discussion of the 

Texas SIP limits or any evidence that the wall-fired limit of 0.05 lb/MMBtu based on a 

30-day rolling average could not be achieved at Reid Gardner. 

f) Existing Permit Limits 

Permits have been issued to several facilities burning a wide range of coals, 

including the same coal burned by Reid Gardner. These permits, discussed below, 

require the use of combustion controls and SCR to meet much lower NOx limits. These 

permits, considered within the framework of constraints unique to Reid Gardner, 

should establish BART. 

Most of these permits have been issued for new units while Reid Gardner is an 

existing facility that would require retrofit of combustion controls and SCR. While 

inadequate space can elevate the cost, space constraints can generally be addressed by 

applying good SCR design practices, including locating the SCR at the tail end of the 

exhaust system. There is no evidence of space constraints at Reid Gardner. 

These permits should serve as a guide in setting BART emission limits for the 

Reid Gardner units. The BART Guidelines note: “... if there is a permit requiring the 

application of a certain technology or emission limit to be achieved for such technology, 

this usually is sufficient justification for you to assume the technical feasibility of that 

technology or emissions limit.”64 There are many such permits that are not discussed in 

the Reid Gardner docket. 

i. Desert Rock Energy Center 

In July 2008, EPA Region 9 issued a PSD permit to Desert Rock Energy Center65

for two 750 MW boilers. This permit sets emission goals based on SCR design. These 

goals are evaluated during a 5-year “NOx Optimization Period” negotiated with the 

Permittee. A 5-year optimization period was chosen to encompass a complete catalyst 

 

63 30 TAC Rule 117.1210(a)(1)(B). 

64 70 FR 39165 (July 6, 2005). 

65 U.S. Environmental Protection Agency, Region 9, PSD Permit Issued Pursuant to Requirement at 

40 CFR 52.21, PSD Permit Number AZP 04-01, Desert Rock Energy Company, July 31, 2008 (Exhibit 32). 
16 

lifecycle plus additional time to compile and analyze operating data. An optimization 

period approach was selected to address uncertainty in performance of SCR with the 

coal to be fired at Desert Rock (Navajo Mine) due to its elevated ash and nitrogen levels 

compared to the then-best performing Parish units, which burn PRB coal.66 A 5-year 

optimization period is, however, excessive. Any uncertainty in SCR performance can be 

resolved in much less time. Any limit within 5 years of rule promulgation would be 

acceptable for BART. 

The Desert Rock permit requires the Permittee to design the SCR system to 

achieve a NOx limit of 0.035 lb/MMBtu on a 365-day rolling average basis. Prior to 

construction, the Permittee must submit design specifications as proof that the SCR 

systems are designed to achieve this limit. The Permittee is also required to submit a 

catalyst management plan, which lays out the measures that will be taken to maintain 

the system and optimize its performance. The NOx permit limits are as follows: 

Table 5: 

Desert Rock NOx permit limits (lb/MMBtu) 

NOx Limit Optimization

Period 

Final

Limit 

24-hr 0.060 0.060

30-day 0.05

365-day 0.05 0.035

a U.S. Environmental Protection Agency, Region 9, EPA Responses to 

Public Comments on the Proposed Prevention of Significant 

Deterioration Permit for the Desert Rock Energy Facility, July 31, 2008 

(Exhibit 33) 

During the Desert Rock optimization period, the NOx emission limits are: 

0.05 lb/MMBtu (365-day rolling average) and 0.060 lb/MMBtu (24-hour block average). 

Following the optimization period, the emission limits are 0.035 lb/MMBtu67 (365-day 

rolling average), 0.05 lb/MMBtu (30-day rolling average), and 0.06 lb/MMBtu (24-hr 

block average) unless a demonstration is made, and EPA approves, that an adjustment 

is required. 

The Desert Rock Permit does not contain a backstop on the adjustment, either up 

or down and thus is not consistent with BART. The BART process requires the best limit 

 

66 U.S. Environmental Protection Agency, Region 9, EPA Responses to Public Comments on the Proposed 

Prevention of Significant Deterioration Permit for the Desert Rock Energy Facility, July 31, 2008 

(Exhibit 33). 

67 We believe the limit of 0.0385 lb/MMBtu in Condition IX.E.4 should have been 0.035 lb/MMBtu, as 

Condition IX.E.2.a requires the SCR to be designed to achieve 0.035 lb/MMBtu and supporting notes in 

the Desert Rock docket identify 0.035 lb/MMBtu as the limit that was discussed. See Notes from October 

16, 2007 U.S Environmental Protection Agency/Sithe Conference Call, Desert Rock Docket ID EPA-R09-

OAR-2007-1110-0091 (Exhibit 34). 
17 

that is feasible to be set. We recommend a similar approach, but with a firm BART 

backstop and a shorter optimization period. Our proposed BART limits do not allow 

backsliding below 0.05 lb/MMBtu. 

ii. Plant Washington 

In April 2010, the Georgia Department of Natural Resources issued a permit to 

Plant Washington for one 850 MW boiler that will burn PRB coal or up to a 50/50 blend 

of eastern bituminous coal (Illinois #6) and sub-bituminous coal.68 The 50/50 blend will 

contain up to 2.23% sulfur and 7.6% ash. The Illinois #6 coal it will burn will contain up 

to 11.6% ash and 3.93% sulfur.69 The NOx emission limits are: 0.050 lb/MMBtu based on 

a 30-day rolling average and 0.030 lb/MMBtu based on a 12-month rolling average 

while firing sub-bituminous coal or a computed weighted average on a 12-month 

rolling basis based on the heat rate weight amount of each, assuming the bituminous 

coal contributes 0.044 lb/MMBtu to the weighted average. The annual average becomes 

effective 6 months after initial startup of the coal boiler, allowing a 6-month 

optimization period. 

iii. Other Permits 

Permits with low NOx emission limits for facilities operating SCR and burning a 

wide range of coals include: 

 0.05 lb/MMBtu (30-day rolling average), Dallman Unit 4, IL (8/06)70

 0.05 lb/MMBtu (30-day rolling average), Sunflower Holcomb, KS (12/10)71

 0.05 lb/MMBtu (12-month rolling average), Wygen 3, WY (2/5/07)72

 0.05 lb/MMBtu (12-month rolling average), Dry Fork, WY (10/15/07)73

 

68 Georgia Department of Natural Resources, Air Quality Permit, Plant Washington, Permit No. 4911-303-

0051P-010-0, April 8, 2010; http://airpermit.dnr.state.ga.us/gaairpermits/PermitPDF.aspx?id=PDF-PI17924, accessed August 22, 2011 (Exhibit 35). 

69 Power4Georgians, LLC, Prevention of Significant Deterioration Air Permit Application, Plant 

Washington, November 26, 2008, Supplemental Data, Exhibit A: Emission Calculations, Table A-2 

(Exhibit 36). 

70 Illinois EPA, Construction Permit – PSD Approval, NSPS Emission Units, Dallman Unit 4, August 10, 

2006, p. 4-13. (Exhibit 37). Limit excludes startups, shutdowns, and malfunctions. 

71 Kansas Department of Health and Environment, Air Emission Source Construction Permit, Holcomb 

Station, December 16, 2010, p. 7; http://www.kdheks.gov/bar/sunflower/Final_Permit.pdf, accessed on 

August 21, 2011 (Exhibit 38). Limit expressed as boiler day average and excludes startups and 

shutdowns, setting separate limits for them. 

72 Wyoming Department of Environmental Quality, Black Hills Corporation, Wygen 3, Permit No. CT4517, February 5, 2007 (Exhibit 39). 
18 

 0.05 lb/MMBtu (12-month rolling average), Spruce, TX (6/28/05)74

 0.05 lb/MMBtu (annual average), Longleaf, GA (5/14/07)75

 0.067 lb/MMBtu (24-hour average), Newmont, NV (5/5/05)76

Dallman, which burns a high ash, high sulfur Illinois coal and Wygen 3 and 

Newmont, which burn PRB coals, are in operation. 

g) Other Considerations for Establishing SCR Limits 

The record for the proposed action does not contain any indication that permits 

issued to other facilities, regulatory determinations, consent decrees, or other 

information were taken into consideration to establish the proposed BART limits. We 

conclude that – by virtue of its failure to address these lower achievable NOx emissions 

– EPA has not established BART for Reid Gardner. As the following comments show, 

NOx emission limits have been established for similar facilities in permits and 

regulatory decisions that are much more aggressive than or equivalent to those that we 

propose as BART for Reid Gardner. 

i. San Juan Generating Station 

 The San Juan Generating Station (“SJGS”), operated by the Public Service 

Company of New Mexico (“PSC NM”), consists of four boilers. Unit 1 is a 360-MW 

wall-fired boiler; Unit 2 is a 350-MW wall-fired boiler; and Units 3 and 4 are 544-MW 

opposed wall-fired boilers. The San Juan boilers were previously retrofitted with new 

low NOx burners, overfire air, and neural networks under a prior Consent Decree and 

thus have lower NOx outlet emissions of 0.30 lb/MMBtu77 than the Reid Gardner 

boilers.78 

 73 Wyoming Department of Environmental Quality, Basin Electric Power Corp., Dry Fork Station, Permit 

No. CT-4631, October 15, 2007 (Exhibit 40). 

74 Texas Department of Environmental Quality, Spruce Special Conditions, Permit Nos. 70492 and PSDTX-1037, June 28, 2005 (Exhibit 41). 

75 Georgia Department of Natural Resources, Air Quality Permit No. 4911-099-0030-P-01-0, Longleaf 

Energy Associates, LLC, May 14, 2007 (Exhibit 42). 

76 State of Nevada, Bureau of Pollution Control, Class I Air Quality Operating Permit, General 

Requirements, No. AP4911-1349, issued to Newmont Nevada Energy Investment, LLC, May 5, 2005 

(Exhibit 43). 

77 Public Service Company of New Mexico, San Juan Generating Station, Best Available Retrofit 

Technology Analysis, prepared by Black & Veatch, June 6, 2007 (Exhibit 44). 

78 NDEP baseline: 0.447-0.462 lb/MMBtu, see Tables 2 and 3. 
19 

On January 5, 2011, EPA Region 6 proposed a NOx BART determination for 

these units under a Federal Implementation Plan (“FIP”) for New Mexico. The EPA 

proposed to require SJGS to meet an emission limit of 0.05 lb/MMBtu individually at 

each unit, for a 30-day rolling average, based on a calendar day. This NOx limit is 

achievable by installing and operating SCR. Because the visibility analysis relied in part 

on assumptions as to the amount of ammonia that would slip out of the SCR and the 

amount of SO2 that the SCR catalyst would convert to sulfuric acid, the EPA also 

proposed a limit on ammonia slip of 2 ppm and on sulfuric acid of 0.000106 lb/MMBtu, 

based on an SCR catalyst SO2 to SO3 conversion of 0.5%.79 These limits are consistent 

with those that we propose for Reid Gardner. On August 4, 2011, the EPA adopted the 

Final SIP for New Mexico which establishes a NOx BART limit of 0.05 lb/MMBtu based 

on a 30-day rolling average boiler operating day and requires that the NOx control 

device be designed to meet an ammonia slip limit of no greater than 2.0 ppm. The New 

Mexico FIP establishes a sulfuric acid mist emission limit of 0.00026 lb/MMBtu and a 

five-year compliance period.80 

ii. Glades Power Park 

In addition, Florida Power and Light (“FP&L”) filed an application in March 

2007 for the Glades facility, two 980-MW boilers firing similar bituminous coal (0.5-1.3% 

sulfur; 6-15% ash) with up to 20% coke. The proposed NOX BACT limit was 

0.05 lb/MMBtu based on a 24-hour rolling average.81 This facility was rejected by the 

Florida Public Service Commission based on need, but nevertheless, demonstrates that 

FP&L considered this limit to be achievable. This FP&L limit is more stringent than the 

0.05 lb/MMBtu limit based on a 30-day rolling average we propose because to meet it, 

the 30-day average must be lower than the 24-hour limit. 

iii. Baldwin Station 

The Baldwin Station in Illinois, consisting of three 585-MW coal-fired units, was 

subject to an NSR enforcement action.82 Matt Haber, EPA Region 9’s BACT expert and 

current Deputy Director of the Air Division, filed an expert report with the court in the 

Baldwin case. His report included historic BACT analyses for the Baldwin units.83

 

79 76 FR 503, 505, 507 (January 5, 2011). 

80 See, New Mexico FIP (Exhibit 1). 

81 Golder Associates, Inc., Air Construction Permit Application and Prevention of Significant 

Deterioration Analysis for FPL Glades Power Park, Glades County, Florida, Prepared for Florida Power & 

Light, December 2006, Table 2-1 (Exhibit 45); Florida Power & Light Glades Response to EPA Comments, 

March 26, 2007, p. 2 (Exhibit 46). 

82 United States v. Illinois Power Co., 245 F. Supp. 2d 951 (S.D. Ill. 2003). 

83 Matt Haber, Best Available Control Technologies for the Baldwin Generating Station, Baldwin, Illinois, 

Prepared for the United States in connection with: United States v. Illinois Power Company and Dynergy 
20 

(A BACT determination is similar to a BART determination.) Mr. Haber’s report 

included a BACT determination for Baldwin Unit 3, a tangentially fired unit burning 

PRB coal. He concluded that BACT for NOx for Baldwin Unit 3 as of 2002 was 

0.015 lb/MMBtu for a new unit and 0.020 lb/MMBtu for a retrofit unit, based on a 

3-hour average, achieved using low-NOx burners, SCR, and a combustion optimization 

system. This limit could be adjusted as high as 0.04 lb/MMBtu if a lower limit was 

demonstrated to be unachievable. This is consistent with conclusions in the notice for 

the Texas SIP and a subsequent permit issued by Region 9 for Desert Rock and is much 

more aggressive than our proposed BART limits for Reid Gardner. 

I.A.2 Cost-Effectiveness at Other Facilities Must Be Considered 

 The BART Guidelines indicate that “in cases where recent retrofits have costeffectiveness values that are within what has been considered a reasonable range, but 

your analysis concludes that costs for the source being analyzed are not considered 

reasonable (A reasonable range would be a range that is consistent with the range of 

cost effectiveness values used in other similar permit decisions over a period of time.) 

... you should provide documentation of any unusual circumstances that exit for the 

source that would lead to cost-effectiveness estimates that would exceed those for 

recent retrofits.”84 This is the situation here. NDEP has eliminated SCR options based on 

costs that have been found to be cost-effective in many other similar permit decisions 

without documenting any unusual circumstances. The conclusion is based on an 

erroneous interpretation of incremental cost-effectiveness. The control costs found to be 

cost-effective in other similar decisions are summarized below. 

 The State of New Mexico concluded that SCR designed to achieve a NOx 

emission rate of 0.03 to 0.07 lb/MMBtu was cost-effective for the San Juan Generating 

Station. The average cost-effectiveness was $5,946/ton to $7,398/ton.85 The 

corresponding incremental cost-effectiveness values relative to ROFA/Rotamix, the 

same combination proposed as BART for Reid Gardner, ranges from $7,339/ton to 

$7,765/ton.86 EPA Region 6 agreed with New Mexico and required SCR designed to 

meet a NOx limit 0.05 lb/MMBtu based on a 30-day rolling boiler operating day 

 

Midwest Generation, Inc., Civil Action No. 99-833-MJR, in the U.S. District Court for the Southern District 

of Illinois, pp. 2, 48-52 (Exhibit 47). 

84 70 FR 39168. 

85 New Mexico Environment Department Air Quality Bureau, BART Determination, Public Service 

Company of New Mexico, San Juan Generating Station, Units 1-4, June 21, 2010, Table 10 and p. 33; 

available at 

http://www.nmenv.state.nm.us/aqb/reghaz/documents/AppxA_NM_SJGS_NOxBARTDetermination

_06212010.pdf, accessed August 21, 2011 (Exhibit 49). 

86 Ibid. 
21 

average. The final cost effectiveness values for the San Juan units, after correcting the 

company’s inflated cost analyses, ranged from $1,757/ton to $2,219/ton.87 Similarly, 

Region 9 itself has proposed SCR as BART for Four Corners designed to meet a NOx 

emission rate of 0.11 lb/MMBtu at $2,515/ton to $3,163/ton,88 after adjusting the 

company’s inflated costs, which ranged from $4,343/ton to $5,484/ton.89 In fact, BART 

determinations have been found cost effective at values ranging up to $15,920/ton, as 

summarized in Exhibit 48. 

 Cost-effectiveness values calculated to establish BACT under the New Source 

Review (“NSR”) program, which uses identical cost metrics, guidance, and relies on the 

same underlying Cost Manual, have a long history of establishing SCR as satisfying 

BACT at cost-effectiveness values ranging from $2,000/ton to over $10,000/ton. 

(See comments filed by EPA in the Milton R. Young case90 and supporting 

documentation for these determinations included in Exhibits 51 to 86.) 

I.B The Reid Gardner NOx Cost Analysis Is Fundamentally Flawed 

The initial cost analyses for Reid Gardner Units 1-3 were prepared for Nevada 

Energy by the consulting company CH2MHill in October 2008 (“the Company Cost 

Analyses”). They are found in Appendix A to the 10/08 CH2MHill BART Analyses, 

respectively. The NDEP adopted this cost analysis wholesale, reporting unaltered costs 

from it in its October 22, 2009 review of the company’s BART Analyses.91 The capital 

cost, first year O&M costs, first year debt service and total annual cost exactly match the 

costs reported in the 10/08 CH2MHill BART Analyses, Appendix A. Thus, NDEP’s 

BART determination, and EPA’s proposal to approve it, are based on the October 2008 

CH2MHill cost analysis. The cost analysis is important because NDEP rejected the most 

effective NOx control options, using SCR, based on cost. We found no evidence in the 

record that any party critically reviewed the company’s cost analysis. The company cost 

analyses are unsupported and deviate in significant ways from the methodology used 

in regulatory cost analyses. 

 

87 New Mexico FIP (Exhibit 1). 

88 75 FR 64,227 

89 74 FR 44,318, Table 3. 

90 Letter from Andrew M. Gaydosh, Assistant Regional Administrator, EPA Region 8, to Terry O’Clair, 

Director, Division of Air Quality, North Dakota Department of Health, Re: EPA’s Comments on the 

North Dakota Department of Health’s April 2010 Draft BACT Determination for NOx for the Milton R. 

Young Station, May 10, 2010 (Exhibit 50). 

91 Compare 10/08 CH2MHill BART Analyses, Appx. A, Tables ‘Input Calculations’, and 10/22/09 NDEP 

BART Review, Table 1. 
22 

 While NDEP relies on the company’s total annual cost, it deviates in calculating 

cost-effectiveness metrics expressed in dollars per ton and in evaluating their 

significance. First, NDEP changed the NOx baseline that it uses to calculate costeffectiveness values in dollars per ton without making adjustments to the company’s 

annual cost. This invalidates the cost effectiveness analysis. Second, the NDEP adopted 

a novel “clear break” theory to reject the top NOx control technologies using SCR based 

on a misinterpretation of EPA’s BART Guidelines regarding average and incremental 

cost-effectiveness. The following sections critique the company’s cost analysis, discuss 

the impact of the mismatch between the baseline and the cost analysis, and explain why 

the cost rejection method is invalid. In sum, NDEP and EPA inappropriately rejected 

the best system of continuous NOx reduction, SCR, based on an unsupported cost 

analysis, sole reliance on incremental cost analysis and a misinterpretation of 

incremental cost-effectiveness. We revised the cost analysis and conclude that BART for 

NOx at Reid Gardner Units 1-3 is LNB/OFA and SCR designed to meet a NOx emission 

limit of 0.05 lb/MMBtu based on a 30-day rolling average based on a boiler 

operating day. 

I.B.1 The Costs to Install SCR on Reid Gardner Are Overestimated 

The original company cost analysis was relied on by both NDEP and EPA in 

making their BART determination. NDEP relied on costs prepared by CH2MHill for NV 

Energy contained in the 10/08 CH2MHill BART Analysis, Appendix A. In addition, in 

response to comments, NDEP prepared an alternative cost-effectiveness analysis to 

demonstrate that its conclusions as to the cost-effectiveness of SCR would not change if 

assumed costs were lower.92 Both of these cost analyses overestimate costs and contain 

many errors. 

The company cost analyses included in Appendix A to the 10/08 CH2MHill 

BART Analyses consist of a series of spreadsheets provided in PDF format. The inputs 

and calculations used to generate the various cost estimates in these spreadsheets are 

unsupported in the record that was available for review. We requested copies of these 

spreadsheets so that we could review the formulas and underlying assumptions used to 

make the cost calculations.93 The spreadsheet provided by NDEP did not contain the 

underlying assumptions and calculations but only “NDEP’s Economic Analysis 

Summary.”94 The original analyses were likely prepared in Excel spreadsheets, which 

allow the inputs and formula used in the calculations to be inspected. It is standard 

practice to produce the original spreadsheets so the basis of calculations can be 

examined. 

 

92 Nevada RH SIP, Appendix D, pp. D-65 - D-68. 

93 Email from to Andrew Gray, Gray Sky Solutions, to Adele Malone, NDEP, Exhibit 20. 

94 Excel spreadsheet ‘Copy Acid Rain Annual Data BART NVE (4).xls’ provided by NDEP (Exhibit 20). 
23 

 Thus, we reverse-engineered the spreadsheets and converted them into Excel 

spreadsheets that show the embedded formulas and assumptions for just the LNB/OFA 

with SCR scenario (option 4). We selected this scenario to analyze as it is the best system 

of continuous reduction for NOx emissions from the three Reid Gardner units and thus 

satisfies BART. We first replicated the results in the 10/09 CH2MHill BART Analyses, 

Appendix A. Our calculations match the CH2MHill calculations within a few percent. 

Differences are due to rounding. Our spreadsheets are included in Attachments 4a, 4b 

and 4c. 

 We next evaluated the assumptions used in this company cost analysis. Our 

comments are discussed below. Based on this review, we revised the company cost 

analyses to correct the errors and omissions that we found. The revised cost analyses 

are attached as Attachments 5a, 5b, and 5c. Our revisions significantly reduced the cost 

of using SCR in the usual configuration, with LNB plus OFA, as summarized below in 

Table 6. The cost-effectiveness values in this table are based on the original baseline 

NOx emissions assumed in the company analysis, not the revised baseline NOx 

emission, subsequently adopted by NDEP. If NDEP’s approach of simply modifying the 

baseline emissions without making concomitant changes in the costs were used, the 

revised cost number would be even smaller as NDEP increased the NOx baseline, 

which increases NOx reductions and hence reduces cost-effectiveness. 

Table 6: 

Average cost-effectiveness 

for control option 5: LNB/OFA + SCR

($/ton NOx)

Unit NDEPa Revisedb

1 3,583 2,179

2 3,334 2,040

3 4,159 2,519

a See Exhibit 4a, 4b, and 4c, respectively. 

 These differ slightly from those reported in 

 the 10/09 CH2MHill BART Analyses, Appendix A 

 due to rounding (3578, 3332, 4155) 

b See Exhibit 5a, 5b, and 5c, respectively 

As discussed in Comment I.A.2, both the original and revised average costeffectiveness values are within what has been considered a reasonable range in other 

similar permit decisions. 
24 

a) Multiple Unit Discounts 

 The vendor costs relied on by NV Energy were estimated on a per-generating 

unit-basis and are identical for all three units.95 There is no evidence that multiple unit 

discounts were factored into the cost analysis. Considerable savings could be achieved 

in capital costs and labor by designing and constructing all three units in one fell swoop 

or constructing a single SCR system to serve the three units. 

 There are many economies involved in designing, procuring, and installing all 

three units from the same vendor. Only one system must be designed, which could be 

replicated for the other two units, reducing engineering and shop setup time. Thus, 

vendors typically offer discounts for awards of multiples of the same system. 

 Capital and labor costs also could be reduced by combining processing units, e.g., 

a single ammonia delivery and injection system and single balance of plant facilities. 

Installing three separate SCR units essentially triples the balance of plant labor and 

increases capital costs. Common facilities should have been designed and costed. 

 We cannot precisely estimate the reduction in cost from taking into account 

multiple units because NV Energy did not supply the underlying vendor quotes. 

However, based on our experience, vendors would offer at least a 5% discount on 

equipment cost for multiple identical units. The revised cost analyses in 

Attachments 5a, 5b, and 5c assume a 5% reduction in the vendor quoted costs. 

b) AFUDC 

 The CH2MHill cost estimates upon which NDEP relied include a charge for 

interest during construction, estimated as 16% of “Major Materials Design and Supply 

Construction.” This charge, generally called “allowance for funds during construction” 

or AFUDC, is disallowed in EPA’s Cost Manual for SCRs.96 NDEP ultimately relied on 

the Cost Manual as NDEP adopted the Company’s analysis wholesale and the 

Company’s analysis claims to have followed it.97 EPA’s position on AFUDC was 

 

95 Compare 10/09 CH2MHill BART Analyses, Appx. A, Tables ‘Economic Analysis Summary’ and ‘Input 

Calculations,’ respectively. 

96 U.S. Environmental Protection Agency, EPA Air Pollution Control Cost Manual, Report EPA/452/B02-001, 6th Ed., January 2002, 

http://www.epa.gov/oaqps001/lead/pdfs/2002_01_cost_control_%20manual.pdf, accessed August 19, 

2011 (Exhibit 87) (hereinafter “Cost Manual”), pdf p. 486, Table 2.5, E (Allowance for Funds during 

Construction) = 0. The EPA Air Pollution Control Cost Manual is the current name for what was 

previously known as the OAQPS Control Cost Manual, the name for the Cost Manual in previous 

(pre-2002) editions of the Cost Manual. 

97 10/08 CH2MHill BART Analyses, p. 3-3, respectively. 
25 

recently upheld in the final FIP for San Juan.98 Thus, we set AFUDC equal to zero in our 

revised cost analyses. 

 AFUDC is an accounting method. Assets under construction do not provide 

service to current customers and thus associated interest and allowed return on equity 

are not charged to current customers. Instead, AFUDC capitalizes these costs and adds 

them to the rate base so that they can be recovered from future customers when the 

assets are used. Thus, these charges represent future cash income to the utility. In other 

words, AFUDC is the accumulated cost of carrying capital and holding it waiting to 

spend, so money can be made in the future, by selling electricity. Future income should 

not be charged against the cost of a SCR in a BART cost-effectiveness analysis. These 

costs are not part of the constant-dollar approach found in the EPA Control Cost 

Manual and should not be included in BART cost-effectiveness analyses. 

c) Owner’s Cost 

 The NV Energy cost analyses include owner’s costs as a separate capital cost, 

estimated as 5% of “Major Materials Design and Supply Construction.” These are 

presumably costs incurred by the owner in managing and implementing a capital 

project. While owners do incur some costs, owners generally do not manage and 

implement capital projects, but rather retain engineering firms, called the owner’s 

engineer, to perform these functions or more commonly, hire an engineering, 

procurement, and construction (“EPC”) contractor to perform the project for a fixed 

cost. Owner’s costs are not separately included in BART cost-effectiveness analyses and 

have been more than double-counted here. In its May 10, 2010 formal comments to the 

North Dakota Department of Health, for example, EPA rejected the inclusion of 

“owner’s costs” in cost analyses for Milton R. Young.99 It has also rejected these costs for 

Four Corners,100 and San Juan101 generating stations. Thus, we set owner’s cost equal to 

zero in our revised cost analyses. 

 

98 New Mexico FIP (Exhibit 1), p. 37 (“Future income should not be charged against the cost of a SCR in a 

BART cost-effectiveness analysis. These costs are not part of the constant dollar approach found in the 

Cost Manual and should not be included in BART cost-effectiveness analyses.”). 

99 Letter from Andrew M. Gaydosh, Assistant Regional Administrator, EPA Region 8, to Terry O’Clair, 

Director, Division of Air Quality, North Dakota Department of Health, Re: EPA’s Comments on the 

North Dakota Department of Health’s April 2010 Draft BACT Determination for NOx for the Milton 

R. Young Station, May 10, 2010 (Exhibit 50). 

100 See Four Corners Technical Support Document, Excel spreadsheet entitled “Four Corners SCR Cost 

Analysis 8-26-10,” from the Four Corners docket #EPA-R09-OAR-2010-0683 (Exhibit 88), Row 52. 

101 New Mexico FIP (Exhibit 1), p. 9 (“As explained more fully in our Complete Response to Comments for 

NM Regional Haze/Visibility Transport FIP document, we also agree with the USFS that owner's costs are 

not an appropriate cost item to include in a BART cost estimate, as owners are not included in the Cost 

Manual.”) 
26 

d) Contingency and Surcharge 

 The NV Energy cost analyses include a contingency estimated as 15% of the 

“Major Materials Design and Supply Construction” and a “surcharge” estimated as 

16% of the “Major Materials Design and Supply Construction.” The record does not 

explain what is included in the surcharge or what the contingency covers. No basis is 

provided for these cost adders. 

 A contingency factor in a regulatory cost-effectiveness analysis “should be 

reserved (and applied to) only those items that could incur a reasonable but 

unanticipated increase but are not directly related to the demolition, fabrication, and 

installation of the system.”102 An example would be a hundred-year flood that 

postpones delivery of materials, but their timely arrival at the job site is not a problem 

unique to the retrofit. The standard contingency factor used in a cost-effectiveness 

analysis, when it is included, is 3% of purchased equipment cost.103 Thus, we revised 

the contingency in our cost analysis to use 3% of “Major Materials Design and Supply 

Construction.” 

e) Capital Recovery 

 The NV Energy cost analyses annualized total capital cost using a first year debt 

service calculation. This calculation is equivalent to the capital recovery method used in 

regulatory cost analyses.104 However, the variables used to annualize capital costs are 

not consistent with those used in regulatory analyses. 

 A capital recovery factor (“CRF”) is used to convert a present value into a stream 

of equal annual payments over a given time at a given interest rate. Under EPA’s 

Control Cost Manual methodology, total capital costs are annualized by calculating an 

annual payment sufficient to finance the investment over its entire life. This payment is 

calculated by multiplying the total capital investment by a capital recovery factor 

calculated from a formula based on interest rate and equipment lifetime. The CRF is 

given by: 

 CRF = [ i(1+i)n]/[(1+i)n -1 ] 

where “i” is the interest rate and “n” is the life of the pollution control equipment. In 

essence, annualization establishes an annual payment sufficient to finance the capital 

 

102 Cost Manual, Chapter 2, Cost Estimation: Concepts and Methodology, Sec. 2.5.4, p. 2-30, pdf 44. 

103 See, for example, Cost Manual, Section 5.2, Post-Combustion Controls, Chapter 1: Wet Scrubbers for 

Acid Gas, Table 1.3 and Section 6, Chapter 1: Baghouses and Filters, Table 1.9. 

104 Cost Manual, pdf 35, Equations 2.7 and 2.8. 
27 

investment for its entire life.105 This payment is equivalent mathematically to the first 

year debt service used in the NV Energy cost analyses. The longer the equipment life 

and the lower the interest rate, the lower the annualized capital costs and the lower the 

cost effectiveness in $/ton of pollutant reduced. 

 NV Energy calculated capital recovery costs assuming an interest rate of 8.55% 

and an SCR lifetime of 20 years. This is inconsistent with the Cost Manual, which 

requires that the CRF be based on an interest rate of 7% and the actual lifetime of the 

control equipment.106 

 

i. SCR Lifetime 

 The lifetime used to calculate the capital recovery factor is the actual (or 

anticipated) service life of the equipment. In BART analyses, the lifetime of a retrofit 

SCR is generally set equal to the remaining useful life of the facility.107 The record is 

silent on the remaining useful life of the Reid Gardner units. The company analysis 

assumed a lifetime for SCR of 20 years. However, this is nothing in the record 

supporting this lifetime. 

The lifetime is important because the shorter the lifetime, the higher the capital recovery 

factor and the higher the annual capital cost used to determine cost-effectiveness. The 

lifetime of an SCR, which is a metal frame packed with catalyst modules, is generally 

equal to the lifetime of the boiler, which might easily be well over 80 years. Units 1, 2, 

and 3 were built in 1965, 1968, and 1976.108 Absent an enforceable condition requiring 

shutdown by a date certain, these units could run more than 20+ additional years if 

they continue to be maintained and upgraded. 

 Many utilities routinely specify 30+ year lifetimes in requests for proposal and to 

evaluate proposals for retrofit SCRs. A study of the economic risks from SCR operation 

at the Detroit Edison Monroe power plant, for example, used 30 years as the anticipated 

lifetime.109 An analysis prepared by Black & Veatch for another facility assumed a 

 

105 Cost Manual, p. 2-21, pdf 35. 

106 While 20 years is used as the equipment life for SCR in an example calculation in the Cost Manual, it 

should be noted that this is merely an assumption for purposes of presenting an example of cost 

estimation for SCR installation and operation in the Cost Manual. See Cost Manual, pdf 492. 

107 New Mexico FIP (Exhibit 1), p . 31 (“The lifetime of a retrofit SCR is generally set equal to the 

remaining useful life of the facility...We conclude there is nothing in the record to support a 20 year 

lifetime for the SCR and believe a 30 year lifetime is justified.”). 

108 70 FR 36459, Table 6. 

109 S.D. Unwin R.W. Johnson, S.W. Rudy, J.E. Delargey, and W. Rogers, Selective Catalytic Reduction 

(SCR) System Design and Operations: Quantitative Risk Analysis of Options, Presented at CCPS 17th 
28 

40-year SCR lifetime.110 Sargent & Lundy assumed a design life of 30 years111 for the 

Navajo Generating Station which burns a similar western bituminous coal. These units 

were built between 1974 and 1976 and are 36 to 38 years old, similar in age to the Reid 

Gardner units. 

When the lifetime of a control affects the BART determination, as here, a 

federally-enforceable restriction is required to prevent further operation after a certain 

date.112 The proposed SIP does not contain a firm shutdown date. Thus, unless the final 

SIP is revised to require a shutdown date consistent with an assumed 20-year lifetime, 

cost effectiveness should be determined based on an SCR lifetime of no less than 

30 years. 

 

ii. Interest Rate 

 The CH2MHill cost analyses upon which NDEP relied assumed an interest rate 

of 8.55%.113 No support is provided for this interest rate. It has long been standard 

practice to use an interest rate of 7% in regulatory cost effectiveness analyses, as this is 

the social cost of borrowing specified for governmental analyses.114 The interest rate 

used to calculate the capital recovery factor for cost analyses is the “social” interest rate 

established by the Office of Management and Budget (“OMB”) for comparison of public 

policy issues.115 The latest real interest rate for cost-effectiveness analyses published by 

OMB is 2.8%.116 The EPA calculated the CRF using both 3% and 7% interest rates in 

determining cost-effectiveness for the Regulatory Impact Analysis for the Final Clean 

Air Visibility rule and the Guidelines for BART Determinations under the Regional 

 

Annual International Conference: Risk, Reliability, and Security, p. 3; available at: http://www.unwinco.com/files%5CSCR-Risk-Paper,CCPS-RRS2002.pdf (Exhibit 89) 

110 Thomas O’Brien, Email to Phil Hayes, EPSR, Dan Yagodinski, WPSC, Gary van Helvoirt, Greg Etvedt, 

WPSC, September 28, 2004, Re: 040928 SCR & SO2 Permitting Issues (revised) 32.0440 (Exhibit 90), 

p. WPS-011905. 

111 Sargent & Lundy, Salt River Project, Najavo Generating Station – Units 1, 2, 3, SCR and Baghouse 

Capital Cost Estimate Report, August 17, 2010, Appendix A (Exhibit 91), Section 1.7, p. 6; available at 

http://en3pro.com/2011/01/30/cost_estimate_report/, accessed August 21, 2011. 

112 70 FR 39169 (July 6, 2005). Where the date that a facility permanently stops operation affects the BART 

determination, “this date should be assured by a federally- or State-enforceable restriction preventing 

further operation.” 

113 10/08 CH2MHill BART Analyses for Units 1-3, Appx. A, Table ‘Input Calculations,’ respectively. 

114 Cost Manual, pdf 27; and U.S. Office of Management and Budget, Circular A-4, September 2003; 

http://www.whitehouse.gov/omb/circulars_a004_a-4/#d, accessed August 22, 2011 (Exhibit 92). 

115 Cost Manual, pdf 26; and U.S. Office of Management and Budget, Circular A-4, September 2003; 

http://www.whitehouse.gov/omb/circulars_a004_a-4/#d, accessed August 22, 2011 (Exhibit 92). 

116 Ibid. 
29 

Haze regulations.117 Thus, we calculated the CRF using a 7% interest rate, which yields 

an upper bound favorable to NV Energy. 

f) Reagent Costs 

Ammonia is used to control NOx in four of the five NOx control options 

evaluated by NDEP, including for SNCR, ROFA with Rotamix, and the two SCR 

options. The cost of ammonia is a significant fraction of the operating and maintenance 

(O&M) costs for all four of these options. For example, for Unit 1, the cost of ammonia 

comprises 41% of the total first year O&M costs for option 2 (LNB/OFA with SNCR); 

35% for option 3 (ROFA with Rotamix); 30% for Option 4 (LNB/OFA with SCR); and 

24% for option 5 (ROFA with SCR).118 The amount of ammonia required by each of 

these control options varies according to the molar ratio of NOx to NH3, the design 

ammonia slip, and the assumed control efficiency. 

All of the cost analyses incorrectly assume the same stoichiometric molar ratio of 

NOx to NH3 for all three control options and ignore the ammonia slip, even though it is 

well known that much more ammonia (3 to 4 times) is required to remove a molecule of 

NOx using SNCR and Rotamix than using SCR.119 SCRs are typically designed with an 

ammonia slip of 2 ppm and SNCR systems, including Rotamix (see Comment I.D.2), 

with an ammonia slip of 5 ppm, or over two times more ammonia wastage. These 

erroneous ammonia calculations result in considerably higher ammonia costs for SCR 

than for SNCR and Rotamix, unfairly skewing the cost analysis in favor of the less 

efficient SNCR technologies. 

I.B.2 NDEP Improperly Modified the Baseline 

The cost analysis discussed above started with baseline NOx emissions for the 

year 2004 and control efficiencies based on vendor quotes. Equipment sizing and 

annual operating expenses were estimated assuming NOx reduction from this original 

baseline. NDEP changed the baseline years and hence the baseline NOx emissions. 

However, NDEP did not modify the control efficiencies or the cost analysis. The new 

baseline emissions are generally higher than the company’s original baseline. Thus, 

there is a mismatch between costs and emission reductions. This makes meaningful 

comment on NDEP’s analysis difficult. The proposed approval should be stayed and 

EPA should request that NDEP correct this fundamental error. 

 

117 See Four Corners Technical Support Document, Excel spreadsheet entitled “Four Corners SCR Cost 

Analysis 8-26-10” from the Four Corners Docket #EPA-R09-OAR-2010-0683 (Exhibit 93). 

118 10/08 CH2MHill BART Analyses, Appx. A, respectively. 

119 IEA Clean Coal Centre, Selective Non-Catalytic Reduction (SNCR) for NOx Control; http://www.ieacoal.org.uk/site/2010/database-section/ccts/selective-non-catalytic-reduction-sncr-for-nox-control

(Exhibit 94.) 
30 

I.B.3 NDEP’s Cost Rejection Methodology Is Invalid 

 NDEP evaluated two SCR control options: (1) ROFA with SCR and 

(2) LNB/OFA with SCR.120 NDEP estimated the average cost effectiveness to control 

NOx at Reid Gardner using these two options as ranging from $2,386 to $3,045 per ton 

of NOx removed. These values are overestimated, but nevertheless, are cost-effective. 

 Selective catalytic reduction has been required to satisfy BART requirements at 

similar sources. Costs for SCR within this range are routinely considered to be costeffective in other BART determinations. However, here, NDEP eliminated these SCR 

options as not cost-effective, based on an erroneous interpretation of incremental cost 

that is inconsistent with both the definition of BART and the BART Guidelines that 

NDEP purports to follow. The BART Guidelines explain that two measures of cost 

should be considered, average cost-effectiveness and incremental cost-effectiveness. 

NDEP calculated both.121 However, in rejecting the SCR options, NDEP relied solely on 

a misinterpretation of incremental cost-effectiveness. The BART Guidelines explain: 

“You should consider the incremental cost effectiveness in combination with the 

average cost effectiveness when considering whether to eliminate a control option.”122 

However, NDEP ignores average cost-effectiveness of the SCR options and the 

fact that it is well within the range routinely found to be cost-effective for similar 

controls in other BART determinations. (See Comment I.A.2.) Instead, it goes off on a 

tangent that is not cited to any source, as discussed below. The NDEP offers no 

explanation of how it considered average cost effectiveness in its decision to reject SCR 

based on cost. 

 The NDEP first plotted the annual cost of each option as calculated by the 

company against the tons removed by that option, based on NDEP’s revised baseline.123

Figure 1 for Unit 3 is attached below. 

 

120 10/22/09 NDEP BART Review, Table 1. 

121 Ibid. 

122 70 FR 39167. 

123 Spreadsheet ‘Copy of Acid Rain Data Annual Data BART NVE (4).xls’ provided via email by Adele 

Malone, NDEP, to Andrew Gray, Gray Sky Solutions, on August 11, 2011 (Exhibit 20) and 10/22/09 

NDEP BART Review, Figure 1. 
31 

Figure 1: 

NDEP’s least-cost envelope for Reid Gardner Unit 3 

(10/22/09 NDEP BART Review, Figure 1, p. 8; 

copied without changes from spreadsheet ‘Copy Acid Rain Annual Data BART NVE (4).xls’ 

provided by NDEP (Exhibit 20); 

the pink square above “LNB w/OFA & SCR” represents “ROFA with SCR”) 

 Plots of annual cost versus corresponding emission reductions are generally 

consistent with the BART Guidelines, when the correct data are used. However, here, 

the plots are meaningless as they mismatch costs and reductions, as discussed 

previously. Further, the NDEP did not follow the incremental cost-effectiveness 

analysis laid out in EPA’s BART Guidelines. 

The BART Guidelines explain in the section “How do I calculate baseline 

emissions:” 

In calculating incremental costs, you: 

(1) Array the control options in ascending order of annualized total costs, 

(2) Develop a graph of the most reasonable smooth curve of the control options, as 

shown in Figure 2. This is to show the ‘‘least-cost envelope’’ discussed above; and 

(3) Calculate the incremental cost effectiveness for each dominant option, which is 

the difference in total annual costs between that option and the next most stringent 

option, divided by the difference in emissions, after controls have been applied, between 

those two control options. For example, using Figure 2, you would calculate incremental 
32 

cost effectiveness for the difference between options B and D, options D and F, options F 

and G, and options G and H.124

The BART Guidelines provide the following example: 

Eight technically feasible control options for analysis are listed. These are represented as 

A through H in Figure 2. The dominant set of control options, B, D, F, G, and H, 

represent the least-cost envelope, as we depict by the cost curve connecting them. Points 

A, C and E are inferior options, and you should not use them in calculating incremental 

cost effectiveness. Points A, C and E represent inferior controls because B will buy more 

emissions reductions for less money than A; and similarly, D and F will buy more 

reductions for less money than C and E, respectively.“125 

The BART Guidelines provide the following example graph to visualize step (2): 

Figure 2: 

EPA BART Guidelines example 

for least-cost envelope determination of dominant/inferior controls 

(70 FR 39168) 

 

124 70 FR 39168. 

125 Ibid. 
33 

In other words, the lower curve determines the “dominant controls and the 

upper curve envelopes the “inferior controls.” The dominant controls buy more 

emission reductions for less money than the inferior controls for roughly the same cost. 

The plotted cost data for Reid Gardner (Figure 1) do not separate into inferior 

and dominate cost curves. (While Figure 1 shows Unit 3, this is true for Units 1 and 2 as 

well.) Rather, all of the cost data for the Reid Gardner units line up on a single cost 

curve. The only dominant and inferior points are the two SCR options and they 

separate along the annual cost axis only because the cost analysis is defective, i.e., the 

same NOx emission reductions were assumed even though the ROFA with SCR option 

should theoretically be able to achieve a higher NOx control efficiency. 

NDEP ignored the fact that there are no inferior and dominant cost curves and 

thus no least-cost envelope, instead noting that the two SCR options have much higher 

annual costs than the other options, as well as higher cost per ton and incremental costs 

but do not achieve proportional reductions in NOx, i.e., costs are four times higher than 

the selected control while NOx reductions are not four times greater. Thus, NDEP 

proclaimed a “clear break” in the plotted points, justifying rejection of the SCR 

options.126 However, this results in BART never being satisfied by the most expensive 

option, a result contrary to the definition of BART and the BART Guidelines. 

There is no such “clear break” theory for determining the cost effectiveness of 

BART. The so-called “clear break” is due to the absence of control options that fall 

within the so-called gap between ROFA with Rotamix and the two SCR options. As an 

example, the “clear break” would still exist even if, for example, SNCR would cost only 

$1/ton, ROFA with Rotamix $3/ton and SCR $10/ton. The so-called “break” would still 

be clearly visible in a graph, yet eliminating SCR at those costs would be nonsensical. 

This problem arises because NDEP did not consider average and incremental cost 

effectiveness together. 

 

126 See, e.g., Appendix D, p. D-59 (“NDEP consistently evaluated the cost and visibility data by looking at 

clear breaks in the cost effectiveness of the BART controls and resulting visibility improvement or 

emissions reductions.”); p. D-64 (“Capital cost increases by more than four times, cost per ton by more 

than twice, and incremental cost by more than seven times, while emissions are reduced by 542 tpy or 

41 percent for unit 1. The clear breaks in these factors support NDEP’s BART determination.”); p. D-65 

(“Nevada deems NDEP’s identification of BART as consistent with the breaks in cost effectiveness and 

visibility improvement/emissions reduction (i.e., cost benefits), as well as the Appendix Y guidance.”); 

p. D-70 (“NDEP has consistently evaluated the proposed BART controls on a unit-by-unit basis by 

identifying the clear breaks in cost-benefit based on cost effectiveness and visibility improvement.”); 

p. D-76 (“NDEP has consistently determined BART through identification of clear breaks in the cost 

effectiveness measures identified in Appendix Y guidance and visibility improvement/emissions 

reductions at the affected Class I areas.”). 
34 

 NDEP’s “clear break” theory turns the concept of cost-effectiveness on its head. 

The BART Guidelines that NDEP claims to have followed lays out an example that 

epitomizes why NDEP’s approach is wrong. It notes: “ 

For example, large capital costs for a control option alone would not preclude selection 

of the control measure if large emission reductions are projected. In such a case, low or 

reasonable cost effectiveness numbers may validate the option as an appropriate BART 

alternative irrespective of the large capital costs.”127

An SCR has a high capital cost compared to the other control options that were 

evaluated. However, SCR also results in a much higher and very large reductions in 

NOx emissions that are not achievable by any of the other options. An SCR is routinely 

designed to reduce 90%+ of the NOx while ROFA with Rotamix, the BART option, tops 

out at about 80% under ideal conditions128 and for Reid Gardner was assumed at 57.7%, 

59.0%, and 38.3% for Units 1-3, respectively.129 

 As explained in Comment I.A.2, the costs per ton of NOx removed estimated by 

NDEP for the SCR options are reasonable compared to other BART determinations. 

Cost-effectiveness is determined by comparing annual cost per ton of pollutant 

removed for the source of interest to the range of cost-effectiveness values for other 

similar permit decisions. If a given cost-effectiveness value falls within the range of 

costs borne by others, it is per se cost-effective unless unusual circumstances exist at the 

source.130 No unusual circumstances are documented for Reid Gardner that would 

render SCR not cost-effective compared to the use of SCR at other similar facilities. 

 When there are no inferior controls, as here, no controls can be eliminated out of 

hand, i.e., there is no “clear break” that allows the SCR options to be rejected. Rather, 

the incremental cost must be considered for each dominant control option.131

Incremental costs were reported by NDEP in the 10/22/09 NDEP BART Review, 

Table 1. The incremental costs for the LNB/OFA with SCR scenario (option 4) relative 

to the ROFA with Rotamix scenario range from $3,688 to $6,085 per incremental ton of 

NOx removed; the incremental costs for the ROFA with SCR scenario (option 5) relative 

 

127 70 FR 39168. 

128 Nalco Mobotec, Multi-pollutant Emission Reduction Technology for Small Utility Boilers, Presented to 

Lake Michigan Air Directors Consortium, Innovative Industrial Source Control and Measurement 

Technologies Workshop, March 24, 2010, pdf 17; 

http://www.ladco.org/about/general/Emissions_Meeting/Fessenden_032410.pdf, accessed August 21, 

2011 (Exhibit 94). 

129 10/09 CH2MHill BART Analyses, Appx. A, Table ‘Input Calculations,’ and NDEP Revised BART 

Determination Review, Table 1, pp. 5-6. 

130 70 FR 39168. 

131 70 FR 39168, Step (3). 
35 

to the ROFA with Rotamix scenario range from $4,444 to $7,280 per incremental ton of 

NOx removed.132 

These costs are greatly overestimated for two reasons. First as explained in 

Comment I.B.1, they include costs that are not allowed in standard regulatory cost 

analyses and contain other errors. Second, NDEP’s incremental cost-effectiveness values 

are significantly overestimated because they are not based on the usual control 

efficiency readily achievable by SCR. The BART Guidelines that NDEP claims to have 

relied on states that “when you evaluate the average or incremental cost effectiveness of 

a control alternative, you should make reasonable and supportable assumptions 

regarding control efficiencies. An unrealistically low assessment of the emission 

reduction potential of a certain technology could result in inflated cost-effectiveness 

figures.”133 This has happened here. The NDEP’s incremental costs assume the SCR 

removes only 78.2-82.2% of NOx. (See Table 1.) As explained in Comment I.A.1, SCR 

systems are routinely designed to achieve, and commonly do achieve, a NOx control 

efficiency of 90% or greater. We revised our cost-effectiveness analyses (provided in 

Attachments 5a, 5b, and 5c) assuming 90% control efficiency for the LNB with SCR 

scenario (option 4). This decreased incremental cost-effectiveness to from $3,713 to 

$2,745/ton NOx removed (Unit 1), $3,552 to $2,656/ton NOx removed (Unit 2), and 

$2,554 to $1,971/ton NOx removed (Unit 3), which is well within the range routinely 

found to be cost-effective for average cost-effectiveness and thus per se cost-effective in 

an incremental analysis. 

 In spite of these overestimates, NDEP’s cost-effectiveness values are within the 

range reported as cost-effective for both average and incremental cost-effectiveness 

values. The New Mexico Environment Department, for example, concluded that SCR 

was cost-effective at similar units based on average cost-effectiveness of $5,946/ton to 

$7,398/ton and incremental cost-effectiveness, relative to ROFA/Rotamix, of $7,399/ton 

to $7,803/ton. 134 The EPA has confirmed New Mexico’s analysis and published a final 

implementation plan requiring SCR at the subject units.135 Thus, absent any unusual 

circumstance, and none is documented in the record, the SCR options are per se costeffective on both an average and incremental cost basis. 

 

132 10/22/09 NDEP BART Review, Table 1, pp. 5-6. 

133 70 FR 39168. 

134 New Mexico Environment Department, Air Quality Bureau, BART Determination, Public Service 

Company of New Mexico, San Juan Generating Station, Units 1-4, June 21, 2010, Table 10 and p. 33 

(Exhibit 49); available at: 

http://www.nmenv.state.nm.us/aqb/reghaz/documents/AppxA_NM_SJGS_NOxBARTDetermination

_06212010.pdf, accessed August 21, 2011. 

135 New Mexico FIP (Exhibit 1). 
36 

I.C EPA Fails to Provide Enforceable Compliance Provisions 

 The last step of the BART determination process is to establish enforceable 

emission limits and compliance dates.136 EPA’s proposed approval of Nevada’s SIP 

claims the BART emission limits are enforceable through Nevada State regulation 

R190-08.137 This regulation sets specific NOx emission limits for Reid Gardner at 

0.20 lb/MMBtu for Units 1 and 2 and at 0.28 lb/MMBtu for Unit 3, based on a 12-month 

rolling average.138 However, as explained below, these limits are not enforceable 

because the averaging time is too long. Further, the proposed BART emission limits for 

NOx, SO2, and PM10 are not enforceable because monitoring and recordkeeping are not 

required. (This comment applies also to Tracy and Fort Churchill Generating Stations.) 

I.C.1 Averaging Time 

 An emission limit consists of two parts: (1) the numerical limit itself and (2) the 

period over which the emissions are averaged. The NOx BART emission limits for Reid 

Gardner in R190-08 are established as 12-month rolling averages. This is a very long 

averaging time and is inappropriate for BART. 

Averaging time plays an important role in determining the stringency of a BART 

limit. For a given limit, the shorter the averaging time, the more stringent the limit 

because less time is available to average out spikes that occur during the stated period. 

A 30-day average, for example, allows 720 hours (30 × 24 = 720) to average out a onehour spike while a 12-month rolling average allows well over 8,000 hours (30 × 24 × 12 

= 8,640) to average out the same spike. 

 The BART guidelines require that emission limits for electric generating units, 

such as Reid Gardner, use an averaging time of 30-days, based on a boiler operating 

day. NDEP instead chose a 12-month rolling average based on NV Energy’s operating 

experience with ROFA/Rotamix139 (the proposed BART technologies for Units 1-3) on 

Unit 4. According to NDEP, Nevada Energy “confronted serious operational problems, 

creating a high degree of variability in the operational characteristics of the unit.”140

 

136 40 CFR 51, Appx. Y (70 FR 39172). 

137 76 FR 36462. 

138 Nevada R190-08, Sec. 4(c).), attached as Appx. A to Nevada RH SIP. 

139 It is unclear from the record whether just ROFA or ROFA plus Rotamix is installed on Unit 4. NDEP’s 

response to comments mentions only “rotating opposed fire air” or ROFA. (See Nevada RH SIP Appx. D, 

p. D-60.) A Mobotech experience list published in March 2010 also lists just ROFA. (See Nalco Mobotec, 

March 24, 2010 (Exhibit 94), pdf 6. However, the McIlvaine Utility Environmental Upgrade Tracking 

System (Exhibit 95) reports Unit 4 is equipped with both ROFA and Rotamix, the BART controls 

recommended for Units 1-3.) 

140 Nevada RH SIP, Appx. D, p. D-60. 
37 

“Thus, “[i]n order to ensure that industry is not out of compliance because of such 

issues, Nevada has chosen the 12-month rolling average.”141 

 First, poor operating experience with ROFA (or ROFA/Rotamix at Unit 4 

provides an insufficient technical basis for selecting this technology as BART at 

Units 1-3. It also attempts to sidestep EPA’s clear direction in its BART Guidelines. The 

relaxation of an emission limit to allow an inferior technology to be selected as BART 

fundamentally undermines the BART determination process. 

 BART is an emission limitation that “is based on the degree of reduction 

achievable through the application of the best system of continuous emission reduction 

for each pollutant which is emitted by an existing stationary facility.” (40 CFR §51.301.) 

If ROFA/Rotamix results in “serious” operational problems, as argued by NDEP in 

carving out an exception to the required averaging time, then surely ROFA/Rotamix is 

not the best system of “continuous” emission reduction. As explained in 

Comment I.A.2, SCR has been demonstrated to continuously achieve much lower NOx 

emission limits on a 30-day rolling average basis than proposed here as BART. 

Alternatively, if ROFA/Rotamix is the best system of continuous emission reduction, 

then it does not qualify for an exception to the standard 30-day averaging period for 

electric generating units (“EGUs”). 

Second, NDEP’s claim of “serious” operational problems with ROFA/Rotamix as 

its technical basis for disregarding BART’s 30-day averaging requirement is illogical. 

This is because Rule R190-08 itself allows the company to comply with the BART 

emission limits using alternative technologies, so long as the emission limits themselves 

are met.142 Thus, under Rule R190-08, ROFA/Rotamix does not have to be used. A more 

reliable technology capable of higher NOx emission reductions, such as SCR, could 

have been and should have been chosen as BART. 

Third, even if one assumes that only ROFA was installed on Unit 4, the 

averaging time exception still would not be warranted because the BART technology is 

ROFA plus Rotamix. The Rotamix component is a selective non-catalytic reduction 

control that is normally operated in concert with ROFA to even out the peaks and 

valleys this exception was meant to address. Thus, there is no justification for the 

averaging time exception. 

 

In sum, the BART guidance in Appendix Y states that BART emission limits for 

EGUs “must” “specify a 30-day rolling average and contain a definition of “boiler 

 

141 Ibid. 

142 Nevada RH SIP, Appx. A, p. A-12. 
38 

operating day.” Nevada’s BART emission limits in Rule R190-08 that EPA is proposing 

to approve do not satisfy either prong of this requirement. 

I.C.2 Monitoring and Recordkeeping 

 BART emission limits must be federally enforceable, which requires practical 

enforceability. The Clean Air Act requires emissions limits such as BART to be met on a 

continuous basis: 

The terms ‘emission limitation’ and ‘emission standard’ mean a requirement established 

by the State or the Administrator which limits the quantity, rate, or concentration of 

emissions of air pollutants on a continuous basis, including any requirement relating to 

the operation or maintenance of a source to assure continuous emission reduction, and 

any design, equipment, work practice or operational standard promulgated under this 

chapter.”143 

and elsewhere: 

To complete the BART process, you must establish enforceable emission limits that reflect 

the BART requirements and require compliance within a given period of time.” 

Emphasis added.144 

Practical enforceability means the source must be able to show continuous 

compliance with each limitation. This requires monitoring, recordkeeping, and 

reporting. As explained by the BART Guidelines, “emissions limits must be enforceable 

as a practical matter (contain appropriate averaging times, compliance verification 

procedures and recordkeeping requirements).”145 Nevada regulation R190-08 does not 

require any monitoring, recordkeeping or reporting. Thus, these limits are not 

enforceable and do not constitute BART. 

I.C.3 Compliance Time 

BART includes “A requirement that each source subject to BART be required to 

install and operate BART as expeditiously as practicable, but in no event later than 

5 years after approval of the implementation plan revision.” 40 CFR 51.308(e)(iv). 

Regulation R190-08 requires that the BART controls must be installed and operating: 

“(a) For NV Energy’s Fort Churchill, Tracy and Reid Gardner generating stations: 

(2) On or before January 1, 2015; or (2) Not later than 5 years after approval of Nevada’s 

 

143 42 U.S.C. §7602(k). 

144 40 CFR Part 51, App. Y, Section V. 

145 70 FR 39172. 
39 

state implementation plan for regional haze by the United States Environmental 

Protection Agency Region 9, whichever occurs first.” Assuming EPA approves the 

Nevada SIP by the end of the current year, this would allow four years to install the 

proposed ROFA/Rotamix controls. This is an excessive amount of time for the 

proposed BART technologies. The subject technologies require placement of air and 

ammonia injection boxes, ducting, supports, fans, tanks, and tie-ins to the existing 

boilers. These types of modifications can be executed, from contract signing to startup, 

in less than a year.146

I.D Alleged Negative Non-Air Quality Environmental Impacts Are 

Mischaracterized and Unsupported in the Record 

The EPA claims, based on NDEP’s analysis, that there are negative non-air 

quality environmental impacts associated with SCR and SNCR compared to the 

selected BART technology, ROFA with Rotamix, including the salability and ultimate 

disposal of fly ash due to higher ammonia levels and the potential for creating a visible 

stack plume. Further, EPA claims that the transportation of ammonia to Reid Gardner 

raises concerns due to the increased likelihood of an accidental release.147 The EPA 

appears to imply that these concerns were contributing factors for NDEP’s decision for 

rejecting SCR and SNCR as BART for Reid Gardner. 

I.D.1 Alleged Impacts Are Not Supported in the Record 

In its analysis for the Nevada RH SIP, NDEP voiced its concerns regarding the 

potential negative non-air quality impacts associated with SCR and SNCR as follows: 

SNCR and SCR installation could impact the salability and disposal of fly ash due to 

ammonia levels and could potentially create a visible stack plume. Transport of ammonia 

to the site may be an issue in the event of an accidental release.148 

NDEP’s analysis did not contain any further discussion of these potential 

negative impacts. Instead, NDEP’s concerns appear to be derived from the following 

vague and unsupported statements found in Nevada Energy’s BART Analyses for Reid 

Gardner Units 1-3: 

 

146 ROFA and ROATMIX Installation, Cape Fear 6 of Progress Energy, Available at: 

http://www.nalcomobotec.com.cn/projects/capefear6-sellsheet.pdf (Exhibit 115) and ICAC, Typical 

Installation Timelines for NOx Emissions Control Technologies on Industrial Sources, December 4, 2006 

(Exhibit 116). 

147 76 FR 36463. 

148 10/22/09 NDEP BART Review, p. 4, emphasis added. 
40 

[For SNCR:] With low-reagent utilization, low temperatures, or inadequate mixing, 

ammonia slip occurs, allowing unreacted ammonia to create problems downstream. The 

ammonia may render fly ash unsalable ... and/or create a visible stack plume. 

... 

SNCR and SCR installation could impact the salability and disposal of fly ash due to 

ammonia levels and could potentially create a visible stack plume, which may negate 

other visibility improvements. Other environmental impacts involve the storage of 

ammonia, especially if anhydrous ammonia is used, and the transportation of the 

ammonia to the power plant site.149 

Nowhere in the record (including EPA’s docket, NDEP’s RH SIP, and Nevada 

Energy’s BART Analyses) is there any further discussion of these potential negative 

non-air quality environmental impacts such as: experience with SNCR and SCR retrofits 

at similar facilities; a discussion of negative experiences with ammonia-contaminated 

fly ash at other facilities; potential for minimization of higher ammonia levels in fly ash; 

a discussion of the mechanisms and likelihood of a visible stack plume; quantification 

of potential economic impacts; an ammonia transportation risk analysis; a comparison 

between SCR and SNCR regarding these risks; etc. (Note also the use of the modal verbs 

“may” and “could” in Nevada Energy’s statements connoting that occurrence of these 

undesirable phenomena is by no means a given.) In other words, there is absolutely no 

support in the record for the NDEP’s and EPA’s statements and the insinuation that 

SCR and SNCR control options were eliminated as BART for NOx emissions from Reid 

Gardner, at least in part, due to these alleged negative non-air quality environmental 

impacts. 

Further, EPA cannot simply state that a potential for negative impacts exists in 

order to eliminate a control technology from consideration. If EPA indeed believed that 

these potential negative impacts were serious enough to affect the viability of SCR or 

SNCR systems as BART for Reid Gardner, it would have to provide a reasoned analysis 

with sufficient detail. This analysis would have to follow a similar approach as 

elimination of a control technology under the best available control technology 

(“BACT”) requirements under the federal Clean Air Act, which EPA lays out as follows 

in its New Source Review Manual: 

The applicant should identify any significant or unusual environmental impacts 

associated with a control alternative that have the potential to affect the selection or 

elimination of a control alternative. Some control technologies may have potentially 

significant secondary (i.e., collateral) environmental impacts. Scrubber effluent, for 

example, may affect water quality and land use. Similarly, emissions of water vapor 

from technologies using cooling towers may affect local visibility. Other examples of 

secondary environmental impacts could include hazardous waste discharges, such as 

spent catalysts or contaminated carbon. Generally, these types of environmental concerns 

 

149 Nevada Energy, BART Analyses for Units 1-3, pp. 3-7 through 3-7, emphasis added. 
41 

become important when sensitive site-specific receptors exist or when the incremental emissions 

reduction potential of the top control is only marginally greater than the next most effective 

option. However, the fact that a control device creates liquid and solid waste that must be 

disposed of does not necessarily argue against selection of that technology as BACT, particularly 

if the control device has been applied to similar facilities elsewhere and the solid or liquid waste 

problem under review is similar to those other applications. On the other hand, where the 

applicant can show that unusual circumstances at the proposed facility create greater 

problems than experienced elsewhere, this may provide a basis for the elimination of 

that control alternative as BACT.150

Here, the incremental emissions reduction potential of the top control options, 

i.e., the two SCR technology combinations, is considerably greater than the next-most 

effective option, i.e., ROFA with Rotamix, which was selected as BART. Specifically, 

according to NDEP, NOx control efficiencies for the SCR technologies range from 78.2% 

to 82.2% for the three units, whereas control efficiencies for ROFA with Rotamix are 

expected at only 38.3% to 59.0%.151 Thus, the potential for negative environmental 

impacts alone would not be reason to eliminate the top control technologies. 

I.D.2 Potential Non-Air Quality Environmental Impacts of SCR Compared to 

SNCR and Rotamix 

Both SCR and SNCR are post-combustion add-on control technologies and are 

fundamentally similar in that they oxidize NOx entrained in the flue gas to form to 

molecular nitrogen (“N2”) and water vapor (“H2O”) using ammonia (“NH3”) or urea 

(“(NH2)2CO”) as a reagent: in the SNCR process, ammonia is injected into the flue gas 

exiting the boiler whereas in the SCR process, ammonia is injected into the hot side of 

the flue gas duct upstream of a catalyst. 

Flue gas temperatures in the upper furnace through the convective pass may 

vary by ±150C (300oF); they depend on both the boiler design and operating conditions 

and vary from one boiler to the next.152 The effective temperature range for SNCR 

systems is 700 F-2000 F (for urea-based systems 1000 F-1900 F) is the optimum 

temperature range in the upper furnace region of the boiler, while SCR systems operate 

at about 700 F.153,154 At lower temperatures the reaction kinetics are slow and ammonia 

 

150 U.S. Environmental Protection Agency, New Source Review Workshop Manual, Prevention of 

Significant Deterioration and Nonattainment Area Permitting (hereinafter “NSR Manual”), Draft October 

1990, p. B.47, emphasis added. 

151 10/22/09 NDEP BART Review, Table 1, pp. 5-6. 

152 Ibid. 

153 California Air Resources Board, Compliance Assistance Technical Manual Series: Stationary Source Air 

Pollution Control Devices and Techniques, Section 310: Selective Non-Catalytic Reduction Control 

Theory and Design; http://www.arb.ca.gov/cap/manuals/cntrldev/sncr_etc/310sncr.htm, accessed 

August 19, 2011 (Exhibit 2). 
42 

passes unreacted through the boiler as the so-called ammonia slip. At higher 

temperatures the reagent oxidizes and additional NOx is generated. Because flue gas 

temperatures are generally set to meet steam generation requirements, they are not 

always ideal for the SNCR process, which rely on appropriate injection temperatures, 

proper mixing of the reagent and flue gas, and prolonged retention time in place of the 

catalyst and are very sensitive to temperature changes. The California Air Resources 

Board (“CARB”) notes that “[v]ariations in the flue gas temperature make the design 

and operation of an SNCR system more difficult...” and “... SNCR requires especially 

efficient temperature and NOx monitoring and diligent operator oversight.”155 

A recent study by Black & Veatch found that “SNCR processes typically require 

three to eight times the theoretical amount of reagent to achieve NOx reductions, as 

compared to SCR systems. The increased reagent consumption is due to reagent 

thermal decomposition, varying temperature, and the lack of a true steady-state 

controlled environment, which tends to increase ammonia slip emissions. Even with 

best efforts (multiple levels of injection, conscientious operator attention, etc.), ammonia 

slip emissions from SNCR systems will be highly variable during load changes. This 

can result in excess or inadequate reagent injection, the increased potential for 

exceeding allowable NOx emission limits, or increased ammonia slip with associated air 

heater pluggage and fly ash contamination.”156 Ammonia and urea-based SNCR 

processes require three or four times as much reagent as SCR systems to achieve similar 

NOx reductions.157

Modern SNCR technologies typically have an ammonia slip of 5 to 10 parts per 

million (“ppm”). In contrast, SCR technologies nowadays are typically designed with a 

2 ppm ammonia slip.158 For example, the recently released FIP for New Mexico which 

 154 Pfafflin J.R., Ziegler E.N. (eds.), Encyclopedia of Environmental Science and Engineering, Vol. 2, CRC 

Press, 2006, p. 766 (Exhibit 96). 

155 Ibid.

156 Black & Veatch, Platte River Power Authority, Rawhide Energy Station, Rawhide NOx Reduction 

Study, January 2009, Rev. 3; available at: 

http://www.cdphe.state.co.us/op/aqcc/meetingmaterials/1210/RegHazeReg3&7/PRPA/PRPS%20REB-EXHIBIT%20A.pdf (Exhibit 97). 

157 IEA Clean Coal Centre, Selective Non-Catalytic Reduction (SNCR) For NOx Control; http://www.ieacoal.org.uk/site/2010/database-section/ccts/selective-non-catalytic-reduction-sncr-for-nox-control

(Exhibit 98.) 

158 U.S. Environmental Protection Agency, Identification of (and Responses to) Potential Effects of SCR 

and Wet Scrubbers on Submicron Particulate Emissions and Plume Characteristics, EPA-600/R-04-107, 

August 2004; available at: http://www.epa.gov/nrmrl/pubs/600r04107/600r04107.pdf, accessed 

August 21, 2011 (Exhibit 99). 
43 

determines BART emission limits for the San Juan Generating Station, requires design 

of the NOx control system with a 2 ppm ammonia slip.159 

The NOx control technology selected by EPA as BART for Reid Gardner, ROFA 

(rotating opposed fire air) with Rotamix, is a “third-generation” SNCR system 

developed by Nalco Mobotec (formerly MobotecUSA), which uses either ammonia or 

urea as a reagent. According to the manufacturer, the SNCR system uses boosted air to 

carry the reagent (ammonia or urea) deep into the furnace cross flow. When combined 

with Nalco Mobotec’s ROFA system, the turbulent air injection and mixing provided by 

Rotamix enables more effective mixing of chemical reagents with combustion products 

in the furnace. Nalco Mobotec asserts that these improved mixing conditions lead to 

higher reagent utilization compared to conventional SNCR systems.160 Nalco Mobotec 

typically designs its Rotamix systems for 5 ppm ammonia slip.161 For Reid Gardner, the 

vendor guarantees a 5 ppm ammonia slip.162 Experience shows that ROFA with 

Rotamix can achieve this design ammonia slip level.163 

Thus, SNCR, including ROFA with Rotamix technology, would result in more 

than twice as much ammonia slip emissions as SCR technologies. In other words, the 

selected BART control option, ROFA with Rotamix, will result in higher ammonia slip. 

Further, it will require the transport and use of more ammonia. Thus, the potentially 

associated non-air quality environmental problems of the selected BART technology 

would be greater than those associated with the much more efficient and highly costeffective but unjustly rejected SCR control options. 

 

159 See Comment I.A.2 and New Mexico FIP (Exhibit 1), p. 111. 

160 See: Nalco Mobotec, ROTAMIX® System; http://www.mobotecusa.com/mb/technology/rotamixsystem.htmhttp://www.mobotecusa.com/mb/technology/rotamix-system.htm accessed August 19, 

2011 (Exhibit 100); and Nalco Mobotec, NOx Control; http://www.mobotecusa.com/mb/expertise/noxcontrol.htm, accessed August 19, 2011 (Exhibit 101). 

161 For example: E.E. Haddad, J.S. Crilley, and B.S. Higgins, Mobotec USA Inc., The Viability and 

Economics of Adding a ROFA®/Rotamix® MobotecSystem to a Selective Catalytic Reduction (SCR) 

Installation, NETL/DOE 2003 Conference on SCR and SNCR for NOx Reduction, Pittsburgh, PA October 

29-30, 2003; http://www.nalcomobotec.com.cn/white_papers/MobotecSystem_ROFA-RotamixSCR.pdf, accessed August 19, 2011 (Exhibit 102). 

162 10/08 CH2MHill BART Analyses, p. 3-6, respectively. 

163 For example: M. Shilling, MobotecUSA, ROFA and ROTAMIX Installation, Cape Fear 6 of Progress 

Energy, p. 19, http://www.netl.doe.gov/publications/proceedings/02/ubc/Shilling.pdf, accessed 

August 19, 2011 (Exhibit 103); and 

G. Moberg, J.O. Blid, S. Wallin, T. Fareid, and J. Ralston, Combined DeNOx/DeSOx and Additional NOx 

Reduction by Cleaning Flue Gas Condensate From Ammonia, PowerGen International, November 30–

December 2, New Orleans 1999; http://www.mobotec.com/eng/pdf/PowerGen99.pdf, accessed August 

19, 2011 (Exhibit 104). 
44 

I.D.3 Impacts of Ammonia Slip on Salability of Fly Ash Are Mischaracterized 

Odor associated with ammonia slip can be a problem and the potential impacts 

associated with ammonia slip due to the operation of SCR and SNCR ammonia 

absorption into fly ash, which may affect disposal or reuse of the ash, are welldocumented.164 However, the occurrence of these impacts is highly site-specific and by 

no means occurs constantly or at all installations. 

An informal phone survey of operating SCR and SNCR installations performed 

for Southern Company showed that “a majority of these plants sometimes experienced 

detectable ammonia odors; however, most were still able to utilize ash for beneficial 

purposes.”165 Experience shows that an ammonia slip of 2 ppm maintains the 

usability/salability of fly ash.166 

As ammonia slip with SCR can be limited to 2 ppm, as discussed before, the 

salability of fly ash should not be impacted if a properly designed SCR system is used. 

However, the ammonia slip from a ROFA/Rotamix system cannot be similarly limited. 

Therefore, the SCR options eliminated by NDEP would have fewer negative impacts 

than the selected ROFA with Rotamix option, which would be designed with a 5 ppm 

ammonia slip. 

I.D.4 Visible Plume Impacts Are Mischaracterized 

EPA, based on NDEP’s Reid Gardner BART Determination Review, claims that 

SCR and SNCR increase the potential for creating a visible stack plume. (76 FR 36463.) 

EPA provides no further information on the origin of this potential visible stack plume. 

There are two reasons the operation of SCR and/or SNCR could lead to a visible stack 

plume: increased ammonia slip and/or increased conversion of SO2 to sulfur 

trioxide (“SO3”). 

 

164 See, for example, U.S. Environmental Protection Agency, Air Pollution Control Technology Fact Sheet, 

Name of Technology: Selective Non-Catalytic Reduction (SNCR), EPA-452/F-03-031, 

http://www.epa.gov/ttn/catc/dir1/fsncr.pdf (Exhibit 105); and U.S. Environmental Protection Agency, 

Air Pollution Control Technology Fact Sheet, Name of Technology: Selective Catalytic Reduction (SCR), 

EPA-452/F-03-032; http://www.epa.gov/ttn/catc/dir1/fscr.pdf, accessed August 19, 2011 (Exhibit 106). 

165 Lamar Larrimore, Effects of Ammonia from Post-combustion NOx Control on Ash Handling and Use, 

Effects on Utilization Applications, Fuel Chemistry Division Preprints 2002, 47(2), 832; available at: 

http://www.anl.gov/PCS/acsfuel/preprint%20archive/Files/47_2_Boston_10-02_0241.pdf

(Exhibit 113). 

166 Lewandowski, Boilers, Emission Controls and the CCPs They Generate, presented at the American 

Coal Ash Association Educational Program for Managers of Coal Combustion Products (CCP), 

Morgantown, WV, June 5-9, 2000 (Exhibit 114), p. 12. 
45 

a) Plume Formation due to Ammonia Slip from SCR and SNCR 

With SCR and SNCR systems, a detached plume may potentially be caused by 

condensation of ammonium chloride as the flue gas cools. The ammonia source is the 

ammonia slip from the post-combustion NOx control system and chlorides can come 

from either the fuel or the flue gas desulfurization (“FGD”) system for SO2 control.167

Although a threshold concentration has not been established, literature indicates that 

plume formation should be considered if both ammonia and chlorides exceed 

15 ppm.168 

In the U.S. permitted ammonia slip levels from SCR and SNCR are typically 

between 2 to 10 ppm169 and ammonia slip levels in practice can be controlled to 

considerably lower levels. Therefore, if the SCR or SNCR are operated at or below 

permitted levels, ammonia slip does not result in plume formation. Further, as 

discussed above, well-controlled SCR systems typically emit less ammonia than 

comparable SNCR control systems. Thus, the proposed BART option, ROFA with 

Rotamix, can be expected to have more of a potential plume formation problem than the 

rejected SCR control technology options. 

b) Plume Formation due to SO2 to SO3 Conversion from SCR 

The operation of an SCR can result in the so-called “blue plume” problem, which 

occurs because the SCR catalyst also in the flue gas to SO3 while it converts NOx to 

elemental nitrogen. According to literature, the SO3 created in the SCR is not effectively 

removed by wet scrubbers.170 Water vapor and SO3 then combine to sulfuric acid 

(“H2SO4”), which is emitted from the stack as an aerosol known as sulfuric acid mist. 

The additional acid aerosol has a significant impact upon stack opacity, creating a 

visible blue plume. 

 

167 L.F. Drbal, P.G. Boston, K.L. Westra, Black & Veatch, Power Plant Engineering, Black & Veatch, 

Springer, 1996, 858 pp, p. 437 (Exhibit 107). 

168 Ibid. 

169 California Air Resources Board, Compliance Assistance Technical Manual Series: Stationary Source Air 

Pollution Control Devices and Techniques, Section 309: Selective Catalytic Reduction Control Theory and 

Design; http://www.arb.ca.gov/cap/manuals/cntrldev/sncr_etc/309scr.htm, accessed August 19, 2011 

(Exhibit 108); and 

California Air Resources Board, Compliance Assistance Technical Manual Series: Stationary Source Air 

Pollution Control Devices and Techniques, Section 310: Selective Non-Catalytic Reduction Control 

Theory and Design; http://www.arb.ca.gov/cap/manuals/cntrldev/sncr_etc/310sncr.htm, accessed 

August 19, 2011 (Exhibit 2). 

170 U.S. Environmental Protection Agency, Identification of (and Responses to) Potential Effects of SCR 

and Wet Scrubbers on Submicron Particulate Emissions and Plume Characteristics, EPA-600/R-04-107, 

August 2004, (Exhibit 99). 
46 

As SO2 concentrations are directly related to coal sulfur content, the creation of a 

blue plume is correlated with coal sulfur content. Thus, one solution to the blue plume 

problem is to use lower sulfur coals. Here, Reid Gardner uses western bituminous coal 

with a relatively low sulfur content of 0.29 to 0.57%.171,172

Visible blue plume issues due to sulfuric acid emissions have not been reported 

for facilities firing Western bituminous coals, such as Reid Gardner (maximum sulfur 

content 0.57%). For example, the EPA in their Federal Implementation Plan (“FIP”) for 

New Mexico rebutted comments regarding the potential for blue plume formation at 

the San Juan Generating Station (“SJGS”): 

Visible plume issues have only been experienced at units that burn high sulfur coal, 

containing greater than 2+% sulfur and typically over 3% sulfur, e.g., Gavin, Ghent. The 

coal burned at SJGS contains 0.77% sulfur, much lower than the amount of sulfur that 

has resulted in visible plume issues elsewhere and is considered to be low sulfur. No 

explanation is provided for why the commenter believes a plume may “materialize” on 

installing SCR.173 

Further, the presence of alkaline metals in coal counteracts SO3 formation. Due 

largely to the abundance of alkaline metals in Western coals, SO3 formation is 

dramatically lower than for low alkali, Eastern bituminous coals. (In fact, for most 

western coals, SO3 levels exiting the boiler are so low that SO3 is commonly injected 

upstream of electrostatic precipitators to reduce ash resistivity to levels that all them to 

operate properly.174) Conversion rates of SO2 to SO3 have been identified for four types 

of coal that correlate inversely with levels of alkaline metals: the estimated values range 

from 0.008 for Eastern bituminous coals, 0.001 for Western bituminous coals and lignite, 

and 0.0005 for Western subbituminous coals when burned in pulverized coal boilers.175

Reid Gardner uses western bituminous coal; hence, operation of an SCR would result in 

low SO2 to SO3 conversion. 

Further, visible plume issues can be addressed by specifying a properly designed 

SCR catalyst with a low conversion rate. Visible plume should not materialize. 

Conversion rates for SO2 to SO3 of as low as 0.1% per catalyst layer can be specified and 

conversion rates of <0.5% are commonly specified, particularly in higher sulfur 

applications. 

 

171 10/08 CH2MHill BART Analyses, Table 2-2, p. 2-3, respectively. 

172 In the past, Reid Gardner also burned West Ridge coals, which the consultant CH2MHill did not 

consider typical. See 10/09 CH2MHill BART Analyses, Footnotes to Table 2-2, p. 2-3, respectively. 

173 New Mexico FIP (Exhibit 1), p. 20. 

174 U.S. Environmental Protection Agency, Identification of (and Responses to) Potential Effects of SCR 

and Wet Scrubbers on Submicron Particulate Emissions and Plume Characteristics, (Exhibit 99), p. 3. 

175 Ibid. 
47 

If the SCR is properly designed to address SJGS’s coal, a Low conversion catalysts 

capable of achieving an SO2 conversion as low as 0.1% per layer of catalyst in the high 

dust, hot (>650 F) position and 0.5% across the entire SCR reactor are common in higher 

sulfur and other applications. Even lower levels can be achieved if the catalyst is 

regenerated.176

Additionally, sorbent injection after the SCR can be used to address blue plume 

issues. Common sorbents used are hydrated lime, a magnesium-hydroxide slurry, 

sodium bisulfite, or Trona (sodium sesquicarbonate).177 These additives are commonly 

and successfully used by utilities firing higher sulfur coals.178

Clearly, with a properly designed SCR and firing western bituminous coal, blue 

plume formation is not an issue for Reid Gardner Units 1-3. 

I.D.5 Transportation Risk Can Be Avoided 

As discussed above, SNCR systems including the proposed BART option, ROFA 

with Rotamix, require three to four times more reagent than SCR. On site, the use of 

anhydrous ammonia for SNCR systems would require the same safety systems, storage 

tanks, and vaporizers as those required for SCR systems. Thus, any risks associated 

with transport of ammonia are greater for SNCR systems than for SCR systems. 

As discussed before, both SCR and SNCR systems can be operated on anhydrous 

ammonia, aqueous ammonia, or urea as reagent. Anhydrous ammonia is toxic by 

inhalation and thus is regulated as a hazardous substance requiring a hazardous safety 

permit when transported in quantities greater than 3,500 gallons.179 Neither aqueous 

ammonia nor urea is classified as hazardous and their transportation does not require 

any special permits. To avoid the transportation risk associated with anhydrous 

ammonia, many coal-fired boilers with SCR and SNCR systems in the U.S. rely on 

aqueous ammonia or urea, options not considered by NDEP for Reid Gardner. Thus, 

the BART analysis is incomplete. 

 

176 New Mexico FIP (Exhibit 1), p. 20. 

177 B. Adams and C. Senior, Curbing the Blue Plume: SO3 Formation and Mitigation, May 15, 2006; 

http://www.powermag.com/environmental/Curbing-the-blue-plume-SO3-formation-andmitigation_564.html, accessed August 19, 2011 (Exhibit 109). 

178 U.S. Environmental Protection Agency, Identification of (and Responses to) Potential Effects of SCR 

and Wet Scrubbers on Submicron Particulate Emissions and Plume Characteristics, (Exhibit 99). 

179 United States Department of Transportation, Frequently Asked Questions (FAQ) - Hazardous 

Matarials [sic]; http://www.fmcsa.dot.gov/safety-security/hazmat/hm-permitting.aspx#one, accessed 

August 21, 2011. 
48 

Aqueous ammonia, while considerably less hazardous than anhydrous 

ammonia, is nonetheless classified as a toxic substance. A safe alternative is therefore to 

generate ammonia from urea on site. Urea is non-hazardous and can be transported to 

and stored safely on site. For example, Chemithon’s SafeDeNOx® process generates 

ammonia from urea for selective catalytic and non-catalytic reduction of NOx.180 

Thus, the risks associated with transportation of ammonia perceived by EPA and 

NDEP can be reduced or avoided altogether. Further, this risk exists for both BART 

and the rejected SCR technologies, but is more significant for the BART controls. 

I.E EPA’s Proposed Higher Controlled Emission Rate for Unit 3 

Compared to Units 1 and 2 for ROFA with Rotamix Is Not Justified 

EPA, based on NDEP’s analysis, proposes a considerably higher NOx emission 

limit as BART for Unit 3 (0.28 lb/MMBtu) than for Units 1 and 2 (0.20 lb/MMBtu).181

The EPA does not discuss why a higher NOx BART limit is proposed for the newer 

Unit 3 (1976) than for Units 1 and 2 (1965 and 1968, respectively) which are the same 

size (100 MW) and would be using on the same BART control technology, i.e., ROFA 

with Rotamix. 

The record fails provide vendor guarantees or any other documentation 

adequate to explain this issue. In comments on the Draft Nevada RH SIP, the National 

Park Service and the Fish and Wildlife Service (“NPS/FWS”) requested a justification 

for the higher NOx limit (and therefore lower control efficiencies) proposed for Unit 3 

compared to those proposed for Units 1 and 2, especially in light of the fact EPA’s 

CAMD data show the lowest current (pre-BART) emission rate of the three units for 

Unit 3.182 In response, NDEP explained that the emission limit for Unit 3 was based on 

control efficiency data presented by NV Energy taking into account the uncertainty in 

vendor emission guarantees and potential for variability. In addition, NDEP stated that 

the higher emission limits are further explained due to the use of different baseline 

emissions (in lb/MMBtu) as the starting point for calculation of emission limits as 

summarized in the Executive Summary of Nevada Energy’s BART Analysis for 

Unit 3.183 We find that NDEP’s explanation is inadequate and does not address the 

issue. NDEP failed to provide any technical justification, why Unit 3 should have higher 

emissions than Units 1 and 2 after installation of the control technology when 

historically it did not. 

 

180 Chemithon, Enviro Safe Denox®, SafeDeNOx® Urea to Ammonia; 

http://www.chemithon.com/Enviro_SafeDenox.html, accessed August 19, 2011 (Exhibit 110). 

181 76 FR 36463. 

182 Nevada RH SIP, Appx. C, pp. C-8 through C-9. 

183 Ibid. 
49 

We have downloaded annual average NOx emission rates for Units 1-3 from 

EPA’s CAMD database for 2001 through 2010. Figure 3 shows these emission rates and 

compares them to the proposed NOx BART limits for ROFA with Rotamix. 

Figure 3: 

Reid Gardner Units 1-3 historic annual average NOx emission rates 

and proposed NOx BART limits 

(data from EPA’s CAMD database)

Figure 3 shows that since 2003, Unit 3 consistently emitted NOx at considerably 

lower emission rates than Units 2 and 3. Moreover, Unit 3 has consistently emitted at or 

below the proposed BART limit of 0.28 lb/MMBtu since 2007, before the 2008 

CH2MHill BART analysis was finalized. By 2010, annual average NOx emission rates 

from Unit 3 decreased to 0.23 lb/MMBtu, 0.05 lb/MMBtu less than the proposed BART 

emission limit of 0.28 lb/MMBtu. Any NOx control technology installed at Reid 

Gardner, including the proposed BART control, ROFA with Rotamix, should further 

decrease these emissions. Thus, NDEP and EPA failed to provide an adequate 

justification that the proposed BART NOx emission limits for Unit 3 should be higher 

than for Units 1 and 2. 
50 

II. NDEP’s BART Determinations Do Not Follow the Methodology 

Assumed by the EPA 

 The EPA’s proposed approval of Nevada’s Regional Haze SIP asserts that the 

BART determinations “were conducted in a manner consistent with the RHR BART 

requirements in 40 CFR 51.308(e), the EPA’s BART Guidelines, and EPA’s Air Pollution 

Control Cost Manual.”184 We agree that the BART determinations must satisfy these 

requirements and follow these guidelines. We further agree that in some places, the 

NDEP asserts that it did follow these requirements. However, we disagree that NDEP’s 

analysis satisfied any of these requirements or made any attempt to follow them. As 

discussed above, NDEP went far astray in its efforts to eliminate SCR as BART. This 

section discusses some of the general flaws in NDEP’s BART determinations, with 

emphasis on Reid Gardner, based on EPA’s claims that these requirements were 

followed. 

II.A NDEP Did Not Follow 40 CFR 51.308(e) 

The EPA’s proposed approval of Nevada’s Regional Haze SIP asserts Nevada 

followed 40 CFR 51.308(e).185 Our review of the record indicates that it did not follow 

this regulation in important respects. 40 CFR 51.308(e) requires that the BART 

determination “must be based on an analysis of the best system of continuous emission 

control technology available and associated emission reduction achievable for each 

BART-eligible source, taking into consideration available technology, costs of 

compliance, energy and non-air quality environmental impacts of compliance, any 

pollution control equipment in use at the source, the remaining useful life of the source, 

and the degree of improvement in visibility which may reasonably be anticipated.”186 

 The chosen BART technology and emission limit for Reid Gardner are not based 

on an analysis of the best system of continuous emission control technology available 

and associated emission reduction. As discussed above, SCR’s are routinely designed to 

achieve 90%+ NOx control to an emission level of 0.05 lb/MMBtu based on a 30-day 

rolling average. NDEP’s analysis for SCR for Reid Gardner is based on an SCR designed 

to remove only 77% of the NOx existing the boiler to 0.085 lb/MMBtu187. Thus, NDEP 

failed entirely to analyze the best system of continuous emission reduction. Instead, it 

analyzed SCR, the best system, designed to operate far below its best performance level, 

overstated its costs, rejected it using an improper costing methodology, claimed non-air 

quality impacts that are actually worse for the BART technology, and substituted an 

 

184 76 FR 36464. 

185 76 FR 36464. 

186 50 CFR 51.308(e)(ii)(A). 

187 10/22/09 NDEP BART Review, Table 1, pp. 5-6. 
51 

inferior technology that does not satisfy the “best system of continuous emission 

reduction.” 

II.B NDEP Did Not Follow EPA’s BART Guidelines 

Section 169A(b)(1) of the Clean Air Act requires EPA to issue regulations to 

provide guidelines to states on the implementation of the regional haze program. EPA 

promulgated the Guidelines for Best Available Retrofit Determinations on July 6, 2005. 

(70 FR 39104-39172.) The BART Guidelines lay out fundamental principles that are 

followed in preparing regulatory cost analyses that have been relied on for decades to 

estimate costs to comply with other various technology requirements of the Clean Air 

Act, including best available control technology (“BACT”), lowest achievable emission 

rate (LAER), maximum achievable control technology (”MACT”), and reasonably 

achievable control technology (”RACT”). NDEP refers to these Guidelines in numerous 

places.188 

EPA mandates use of the BART Guidelines in making BART determinations for 

power plants with a generating capacity of 750 Megawatts (“MW”) or greater.189 With 

exception of the Mohave Generating Station, all power plants in Nevada subject to 

BART, i.e., Nevada Energy’s Tracy, Churchill, and Reid Gardner generating stations, 

have generating capacities less than the 750 MW threshold above which the use of 

EPA’s BART Guidelines for BART determinations becomes mandatory.190 (The 

operating permit for the Mohave Generating Station was terminated and the facility 

permanently ceased operation on December 31, 2005.191) NDEP has made clear that it is 

neither legally required to nor did it follow EPA’s BART Guidelines for its BART 

determinations for the other three facilities.192 However, EPA relies on the assumption 

that it did in its proposed SIP approval. Our review of the record indicates that NDEP 

did not follow the BART Guidelines in important respects. Our review of the record 

also did not identify any reasoned alternative approach to making a BART 

determination. 

 

188 For example, 10/22/09 NDEP BART Review, p. 1 (“Explanation: BOLD text below identifies the 

Guidelines for BART Determinations under the Regional Haze Rule in Appendix Y of 40 CFR 51,” 

implying that NDEP’s review was conducted according to the BART Guidelines.) 

189 70 FR 39108. 

190 76 FR 36462-36463. 

191 76 FR 36463. 

192 Nevada RH SIP, Appx. C, p. C-3. 
52 

II.B.1 Averaging Time Is Incorrect 

NDEP selected a 12-month rolling average for monitoring emissions of nitrogen 

oxides (“NOx”) from Tracy, Fort Churchill and Reid Gardner generating stations 

instead of the 30-day rolling average specified in EPA’s BART Guidelines.193 NDEP in 

their response to comments on the draft Nevada RH SIP expressly rejected 

recommendations by the Federal Land Managers (“FLMs”) to specify a shorter 

averaging time of 30 days for monitoring of NOx emissions because Nevada’s BARTeligible power plants (with exception of the Mohave Generating Station) have 

generating capacities less than the 750 MW threshold and are thus not required to 

follow the guidelines.194 

 

Further, neither NDEP nor the EPA specify monitoring times, times of operation, 

fuel input, or other indices of operating conditions sufficient to show compliance or 

non-compliance or provide for adequate reporting and recordkeeping so that air quality 

agency personnel can determine the compliance status of the source, as required by the 

EPA’s BART Guidelines to ensure that proposed BART emission limits are 

enforceable.195 

II.B.2 Design Parameters Are Missing 

 The Guidelines lay out the process for conducting a BART cost analysis. The first 

major step in this process is to identify the design parameters for each emission 

control.196 This is fundamental to any cost analysis for any purpose and is not specific to 

these Guidelines. (See, for example, the EPA’s New Source Review Manual at page B.32: 

“Before costs can be estimated, the control system design parameters must be 

specified.”) One cannot develop a meaningful cost analysis without specifying the 

relevant design parameters. 

 The docket in this case does not contain the design parameters used to evaluate 

the BART controls. The 10/08 CH2MHill BART Analysis, Appendix A, includes certain 

“input calculations,” but these do not include the pollution control design parameters. 

For example, for SCR, the record does not disclose any of the key SCR design 

parameters, including the ammonia slip, the SO2 to SO3 conversion rate, the catalyst 

configuration (e.g., 3 catalyst layers + 1 spare or 3+1), the catalyst life, the catalyst 

volume, number of reactors, catalyst specific area, catalyst pitch, reactor and catalyst 

 

193 76 FR 36462-36463; Nevada RH SIP, p. 5-12; 70 FR 39172. 

194 Nevada RH SIP, Appx. C, p. C-3. 

195 70 FR 39172; Nevada RH SIP, §5.5. 

196 70 FR 39166. 
53 

dimensions, and detailed coal quality information. (See, e.g., a typical catalyst design for 

another facility shown in Exhibit 111.197) 

 This type of information is commonly provided when costing an SCR and is 

required here to assess the claimed capital cost of the SCR and to determine if it satisfies 

the “best system of continuous emission reduction.” The same is true for SNCR and 

ROFA Rotamix, which likewise are presented without the underlying design 

parameters, e.g., ammonia slip, NOx to NH3 molar ratio198, etc. Thus, it is not possible to 

determine if the proposed design of any of the NOx controls represent the “best system 

of continuous emission reduction.” 

II.B.3 Equipment List Is Missing 

 Second, the BART Guidelines indicate that a cost analysis must include a list of 

equipment and associated costs.199 This is also fundamental to cost analysis, regardless 

of the guidance that is followed. The NSR Manual, for example, explains that the second 

step of a cost analysis is to “to list and cost each major piece of equipment within the 

battery limits.”200 Standard cost estimating textbooks explain the importance of this key 

foundational step.201 

 The cost analyses that EPA and NDEP relied upon do not identify the equipment 

that it costed, instead reporting only lump sum estimates for each control from vendor 

quotes. These lump sums add up costs for individual pieces of equipment required to 

build the control systems. The underlying vendor quotes are not supplied, preventing 

any meaningful review or revision to accommodate NDEP’s change in baseline. It is not 

possible to evaluate a lump sum cost without the supporting vendor quote, which will 

typically identify and separately cost the components. In addition, the cost analyses 

include certain “balance of plant” costs that are not broken out so their components can 

be individually assessed. 

 Applicants seeking to avoid the installation of more effective, but more costly 

controls, such as SCR, frequently pad cost estimates with items that are not part of and 

are not required for the control. These include costs for brand new electrical systems, 

 

197 CERAM, Project: IPALCO Harding St Unit 7, July 7, 2003. 

198 The 10/08 CH2MHill BART Analyses provide the stoichiometric ratio for NH3 to NOx conversion (1.0) 

but fail to provide the ratio that is expected to be achieved for operating conditions. These, as discussed 

in Comment I.B.1.f, are higher than 1.0 due to ammonia slip. 

199 70 FR 39166. 

200 NSR Manual, p. B.33. 

201 K.K. Humphreys and P. Wellman, Basic Cost Engineering, 3rd Ed., Marcel Dekker, Inc., 1996, Chapter 

2, Table 2.3, and Chapter 3 (Exhibit 112). 
54 

induced draft fans, stacks, conversion of the boiler from pressurized to balanced draft, 

SCR bypasses, and major modifications to air preheaters, among others. These types of 

costs are unwarranted for retrofit SCRs on units burning low sulfur coal and only serve 

to artificially inflate costs. It is impossible to determine whether the capital costs for the 

SCR options at Reid Gardner, for example, include unnecessary costs as the components 

of the capital cost estimate are not specified, i.e., they are presented as two lump sums: 

(1) major materials design and supply and (2) balance of plant. 

 Similarly, applicants seeking to install a cheaper control can understate its cost to 

favor its selection by not including all of the components. The NDEP concluded that 

BART for NOx emissions at Reid Gardner is satisfied by ROFA with Rotamix. This 

combination includes several pieces of equipment. The ROFA requires a ROFA fan, 

ROFA boxes, ROFA dampers, and expansion joints. The Rotamix equipment includes a 

fan, reagent injection devices, tanks, pumps, and filters. There is no way to determine if 

the costs that NDEP relied on include all of the equipment necessary to operate the 

ROFA with Rotamix option. 

 The EPA explains in the BART Guidance (that it alleges NDEP followed): “The 

analysis should provide a clear summary list of equipment and the associated control 

costs. Inadequate documentation of the equipment whose emissions are being 

controlled is a potential cause for confusion in comparison of costs of the same controls 

applied to similar sources.”202 The costs used in the NDEP analysis are undocumented, 

preventing meaningful review. 

II.B.4 Documentation for Cost Estimates Is Missing 

 Third, the BART Guidelines that EPA alleges NDEP followed recommends 

documenting assumptions regarding design parameters and equipment costs estimates, 

with either data supplied from an equipment vendor or citations to a referenced source, 

such as EPA’s Control Cost Manual (discussed below). The EPA explains: “You should 

include documentation for any additional information you used for the cost 

calculations, including any information supplied by vendors that affects your 

assumptions regarding purchased equipment costs, equipment life, replacement of 

major components, and any other elements of the calculation that differs from the Cost 

Control Manual.”203 

 This standard practice is required for all regulatory cost analyses.204 However, 

here, the cost analysis NDEP relied on and EPA is proposing to adopt without any 

 

202 70 FR 39166. 

203 70 FR 39166, Footnote 15. 

204 See, e.g., NSR Manual, p. B.33. 
55 

independent analysis is wholly unsupported. NDEP, and consequently, EPA, took 

Nevada Energy’s assumptions for cost analyses for each control technology at face 

value. This includes NOx control efficiencies; economic factors such as interest rates, 

discount rates, and plant economic life; installed capital costs; total fixed and variable 

operating and maintenance costs; reagent costs; catalyst replacement costs; auxiliary 

power costs; etc. There is no support for any input into the analyses, including the 

calculations themselves that were used to arrive at the cost effectiveness numbers. As 

explained elsewhere, we had to reverse-engineer the cost spreadsheets as the record 

does not contain and NDEP did not supply spreadsheets that disclosed these 

calculations. 

 Documented costs are particularly critical here as cost is the primary parameter 

that NDEP used to reject the most effective NOx control technology, SCR. The record 

indicates that NDEP accepted the company’s cost estimate without critically reviewing 

it. In fact, critical review would not have been feasible as the costs are unsupported. 

II.B.5 Other Missing Documents, Modeling Files, and Information 

Documents, modeling files and information missing from EPA’s docket for the 

proposed rule include: 

 Appendix B (BART Protocol) to Nevada Energy’s BART Analyses for Reid 

Gardner Units 1-3.205 

 Input calculations to support NDEP’s economic analysis contained in the 

10/22/09 NDEP BART Review.206 

 Support for NDEP’s baseline emission scenarios for NOx (using acid rain 

data) and PM10 (using annual emissions reported to NDEP) for calendar 

years 2001 through 2007 as described in 10/22/09 NDEP BART Review, 

p. 6.207 

 Vendor guarantees or quotes obtained for and relied upon for the 10/08 

CH2MHill BART Analyses. 

 

205 Andrew Gray, Gray Sky Solutions requested this document and received it from Adele Malone, 

NDEP, via mail. 

206 Adele Malone, NDEP, in an email to Andrew Gray, Gray Sky Solutions, August 9, 2011, declared 

“With respect to the input files for alternative NOx control scenarios, the NDEP doesn’t have these files. 

We haven’t requested additional files from NV Energy.” (See Exhibit 20.) 

207 Excel spreadsheet ‘Copy Acid Rain Annual Data BART NVE (4).xls’ provided via email by Adele 

Malone, NDEP, to Andrew Gray, Gray Sky Solutions, on August 11, 2011 (Exhibit 20). 
56 

 Report by Nevada Energy entitled “Fly Ash Conveyor System – Units 1, 2, 

and 3,” dated January 18, 2007, cited in 10/08 CH2MHill BART Analyses, 

Footnotes to Table 2-2, p. 2-3, respectively. 

 Visibility modeling files. 

 Appendices A through F to Letter from National Park Service (“NPS”) and 

U.S. Fish and Wildlife Service (“USFWS”) to NDEP.208 

II.B.6 Costing Methodology Is Inconsistent With BART Guidelines 

 The BART Guidelines set out an approach to determine the “cost effectiveness” 

of pollution controls.209 Under these Guidelines, cost-effectiveness, measured in dollars 

per ton of pollutant removed, is calculated according to the EPA Air Pollution Control 

Cost Manual or “Cost Manual,” which EPA also alleges NDEP followed.210 However, as 

explained elsewhere in these comments, NDEP did not follow the methodology 

recommended in the BART Guidelines and in fact used a method to determine costeffectiveness that has never been approved for any regulatory cost analysis under the 

Clean Air Act and would always result in rejecting the “best system of continuous 

emission reduction.” 

II.C NDEP’s Analysis Did Not Follow EPA’s Air Pollution Control Cost 

Manual 

 The EPA’s proposed approval of Nevada’s Regional Haze SIP asserts that NDEP 

followed EPA’s Air Pollution Control Cost Manual.211 Our review of the record 

indicates that NDEP did not follow the Cost Manual. The NDEP cost analysis deviates 

in significant ways from the Cost Manual, as documented in Comment I.B. 

 

208 Letter from Chris Shaver, National Park Service, and Sandra Silva, U.S. Fish and Wildlife Service, to 

Michael Elges, Nevada Division of Environmental Protection, March 6, 2009, EPA-R09-OAR-2011-0130-

0041. 

209 70 FR 39166 to 39172. 

210 76 FR 36464. 

211 76 FR 36464.